Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Document Information [Line Items] | |||
Entity Registrant Name | SOUTHERN CO | ||
Entity Central Index Key | 92,122 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 47.9 | ||
Entity Common Stock, Shares Outstanding (in shares) | 1,008,159,482 | ||
ALABAMA POWER CO | |||
Document Information [Line Items] | |||
Entity Registrant Name | ALABAMA POWER CO | ||
Entity Central Index Key | 3,153 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding (in shares) | 30,537,500 | ||
GEORGIA POWER CO | |||
Document Information [Line Items] | |||
Entity Registrant Name | GEORGIA POWER CO | ||
Entity Central Index Key | 41,091 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding (in shares) | 9,261,500 | ||
GULF POWER CO | |||
Document Information [Line Items] | |||
Entity Registrant Name | GULF POWER CO | ||
Entity Central Index Key | 44,545 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding (in shares) | 7,392,717 | ||
MISSISSIPPI POWER CO | |||
Document Information [Line Items] | |||
Entity Registrant Name | MISSISSIPPI POWER CO | ||
Entity Central Index Key | 66,904 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding (in shares) | 1,121,000 | ||
SOUTHERN POWER CO | |||
Document Information [Line Items] | |||
Entity Registrant Name | SOUTHERN POWER CO | ||
Entity Central Index Key | 1,160,661 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding (in shares) | 1,000 | ||
SOUTHERN Co GAS | |||
Document Information [Line Items] | |||
Entity Registrant Name | SOUTHERN Co GAS | ||
Entity Central Index Key | 1,004,155 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding (in shares) | 100 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating Revenues: | |||||
Retail electric revenues | $ 15,330,000,000 | $ 15,234,000,000 | $ 14,987,000,000 | ||
Wholesale electric revenues | 2,426,000,000 | 1,926,000,000 | 1,798,000,000 | ||
Other electric revenues | 681,000,000 | 698,000,000 | 657,000,000 | ||
Natural gas revenues | 3,791,000,000 | 1,596,000,000 | 0 | ||
Other revenues | 803,000,000 | 442,000,000 | 47,000,000 | ||
Total operating revenues | 23,031,000,000 | 19,896,000,000 | 17,489,000,000 | ||
Operating Expenses: | |||||
Fuel | 4,400,000,000 | 4,361,000,000 | 4,750,000,000 | ||
Purchased power | 863,000,000 | 750,000,000 | 645,000,000 | ||
Cost of natural gas | 1,601,000,000 | 613,000,000 | 0 | ||
Cost of other sales | 513,000,000 | 260,000,000 | 0 | ||
Other operations and maintenance | 5,481,000,000 | 5,240,000,000 | 4,416,000,000 | ||
Depreciation and amortization | 3,457,000,000 | 2,923,000,000 | 2,395,000,000 | ||
Depreciation and amortization | 3,010,000,000 | 2,502,000,000 | 2,034,000,000 | ||
Taxes other than income taxes | 1,250,000,000 | 1,113,000,000 | 997,000,000 | ||
Estimated loss on Kemper IGCC | 3,362,000,000 | 428,000,000 | 365,000,000 | ||
Total operating expenses | 20,480,000,000 | 15,267,000,000 | 13,207,000,000 | ||
Operating Income | 2,551,000,000 | 4,629,000,000 | 4,282,000,000 | ||
Other Income and (Expense): | |||||
Allowance for equity funds used during construction | 160,000,000 | 202,000,000 | 226,000,000 | ||
Earnings from equity method investments | 106,000,000 | 59,000,000 | 0 | ||
Interest expense, net of amounts capitalized | (1,694,000,000) | (1,317,000,000) | (840,000,000) | ||
Other income (expense), net | (55,000,000) | (93,000,000) | (39,000,000) | ||
Total other income and (expense) | (1,483,000,000) | (1,149,000,000) | (653,000,000) | ||
Earnings Before Income Taxes | 1,068,000,000 | 3,480,000,000 | 3,629,000,000 | ||
Income taxes | 142,000,000 | 951,000,000 | 1,194,000,000 | ||
Consolidated Net Income | 926,000,000 | 2,529,000,000 | 2,435,000,000 | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 38,000,000 | 45,000,000 | 54,000,000 | ||
Net income attributable to noncontrolling interests | 46,000,000 | 36,000,000 | 14,000,000 | ||
Net income after dividends on preferred and preference stock | $ 842,000,000 | $ 2,448,000,000 | $ 2,367,000,000 | ||
Earnings per share — | |||||
Basic (in dollars per share) | $ 0.84 | $ 2.57 | $ 2.60 | ||
Diluted (in dollars per share) | $ 0.84 | $ 2.55 | $ 2.59 | ||
Average number of shares of common stock outstanding — (in millions) | |||||
Basic (in shares) | 1,000 | 951 | 910 | ||
Diluted (in shares) | 1,008 | 958 | 914 | ||
ALABAMA POWER CO | |||||
Operating Revenues: | |||||
Retail electric revenues | $ 5,458,000,000 | $ 5,322,000,000 | $ 5,234,000,000 | ||
Wholesale revenues, non-affiliates | 276,000,000 | 283,000,000 | 241,000,000 | ||
Wholesale revenues, affiliates | 97,000,000 | 69,000,000 | 84,000,000 | ||
Other revenues | 208,000,000 | 215,000,000 | 209,000,000 | ||
Total operating revenues | 6,039,000,000 | 5,889,000,000 | 5,768,000,000 | ||
Operating Expenses: | |||||
Fuel | 1,225,000,000 | 1,297,000,000 | 1,342,000,000 | ||
Purchased power, non-affiliates | 170,000,000 | 166,000,000 | 171,000,000 | ||
Purchased power, affiliates | 158,000,000 | 168,000,000 | 180,000,000 | ||
Other operations and maintenance | 1,652,000,000 | 1,510,000,000 | 1,501,000,000 | ||
Depreciation and amortization | 888,000,000 | 844,000,000 | 780,000,000 | ||
Depreciation and amortization | 736,000,000 | 703,000,000 | 643,000,000 | ||
Taxes other than income taxes | 384,000,000 | 380,000,000 | 368,000,000 | ||
Total operating expenses | 4,325,000,000 | 4,224,000,000 | 4,205,000,000 | ||
Operating Income | 1,714,000,000 | 1,665,000,000 | 1,563,000,000 | ||
Other Income and (Expense): | |||||
Allowance for equity funds used during construction | 39,000,000 | 28,000,000 | 60,000,000 | ||
Interest expense, net of amounts capitalized | (305,000,000) | (302,000,000) | (274,000,000) | ||
Other income (expense), net | (14,000,000) | (21,000,000) | (32,000,000) | ||
Total other income and (expense) | (280,000,000) | (295,000,000) | (246,000,000) | ||
Earnings Before Income Taxes | 1,434,000,000 | 1,370,000,000 | 1,317,000,000 | ||
Income taxes | 568,000,000 | 531,000,000 | 506,000,000 | ||
Consolidated Net Income | 866,000,000 | 839,000,000 | 811,000,000 | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 18,000,000 | 17,000,000 | 26,000,000 | ||
Net income after dividends on preferred and preference stock | 848,000,000 | 822,000,000 | 785,000,000 | ||
GEORGIA POWER CO | |||||
Operating Revenues: | |||||
Retail electric revenues | 7,738,000,000 | 7,772,000,000 | 7,727,000,000 | ||
Wholesale revenues, non-affiliates | 163,000,000 | 175,000,000 | 215,000,000 | ||
Wholesale revenues, affiliates | 26,000,000 | 42,000,000 | 20,000,000 | ||
Other revenues | 383,000,000 | 394,000,000 | 364,000,000 | ||
Total operating revenues | 8,310,000,000 | 8,383,000,000 | 8,326,000,000 | ||
Operating Expenses: | |||||
Fuel | 1,671,000,000 | 1,807,000,000 | 2,033,000,000 | ||
Purchased power, non-affiliates | 416,000,000 | 361,000,000 | 289,000,000 | ||
Purchased power, affiliates | 622,000,000 | 518,000,000 | 575,000,000 | ||
Other operations and maintenance | 1,653,000,000 | 1,960,000,000 | 1,844,000,000 | ||
Depreciation and amortization | 1,100,000,000 | 1,063,000,000 | 1,029,000,000 | ||
Depreciation and amortization | 895,000,000 | 855,000,000 | 846,000,000 | ||
Taxes other than income taxes | 409,000,000 | 405,000,000 | 391,000,000 | ||
Total operating expenses | 5,666,000,000 | 5,906,000,000 | 5,978,000,000 | ||
Operating Income | 2,644,000,000 | 2,477,000,000 | 2,348,000,000 | ||
Other Income and (Expense): | |||||
Interest expense, net of amounts capitalized | (419,000,000) | (388,000,000) | (363,000,000) | ||
Other income (expense), net | 33,000,000 | 38,000,000 | 61,000,000 | ||
Total other income and (expense) | (386,000,000) | (350,000,000) | (302,000,000) | ||
Earnings Before Income Taxes | 2,258,000,000 | 2,127,000,000 | 2,046,000,000 | ||
Income taxes | 830,000,000 | 780,000,000 | 769,000,000 | ||
Consolidated Net Income | 1,428,000,000 | 1,347,000,000 | 1,277,000,000 | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 14,000,000 | 17,000,000 | 17,000,000 | ||
Net income after dividends on preferred and preference stock | 1,414,000,000 | 1,330,000,000 | 1,260,000,000 | ||
GULF POWER CO | |||||
Operating Revenues: | |||||
Retail electric revenues | 1,281,000,000 | 1,281,000,000 | 1,249,000,000 | ||
Wholesale revenues, non-affiliates | 57,000,000 | 61,000,000 | 107,000,000 | ||
Wholesale revenues, affiliates | 108,000,000 | 75,000,000 | 58,000,000 | ||
Other revenues | 70,000,000 | 68,000,000 | 69,000,000 | ||
Total operating revenues | 1,516,000,000 | 1,485,000,000 | 1,483,000,000 | ||
Operating Expenses: | |||||
Fuel | 427,000,000 | 432,000,000 | 445,000,000 | ||
Purchased power | 155,000,000 | 142,000,000 | 135,000,000 | ||
Purchased power, affiliates | 15,000,000 | 16,000,000 | 35,000,000 | ||
Other operations and maintenance | 359,000,000 | 336,000,000 | 354,000,000 | ||
Depreciation and amortization | 149,000,000 | 179,000,000 | 152,000,000 | ||
Depreciation and amortization | 137,000,000 | 172,000,000 | 141,000,000 | ||
Taxes other than income taxes | 116,000,000 | 120,000,000 | 118,000,000 | ||
Loss on Plant Scherer Unit 3 | 33,000,000 | 0 | 0 | ||
Total operating expenses | 1,227,000,000 | 1,202,000,000 | 1,193,000,000 | ||
Operating Income | 289,000,000 | 283,000,000 | 290,000,000 | ||
Other Income and (Expense): | |||||
Interest expense, net of amounts capitalized | (50,000,000) | (47,000,000) | (49,000,000) | ||
Other income (expense), net | (10,000,000) | (5,000,000) | 8,000,000 | ||
Total other income and (expense) | (60,000,000) | (52,000,000) | (41,000,000) | ||
Earnings Before Income Taxes | 229,000,000 | 231,000,000 | 249,000,000 | ||
Income taxes | 90,000,000 | 91,000,000 | 92,000,000 | ||
Consolidated Net Income | 139,000,000 | 140,000,000 | 157,000,000 | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 4,000,000 | 9,000,000 | 9,000,000 | ||
Net income after dividends on preferred and preference stock | 135,000,000 | 131,000,000 | 148,000,000 | ||
MISSISSIPPI POWER CO | |||||
Operating Revenues: | |||||
Retail electric revenues | 854,000,000 | 859,000,000 | 776,000,000 | ||
Wholesale revenues, non-affiliates | 259,000,000 | 261,000,000 | 270,000,000 | ||
Wholesale revenues, affiliates | 56,000,000 | 26,000,000 | 76,000,000 | ||
Other revenues | 18,000,000 | 17,000,000 | 16,000,000 | ||
Total operating revenues | 1,187,000,000 | 1,163,000,000 | 1,138,000,000 | ||
Operating Expenses: | |||||
Fuel | 395,000,000 | 343,000,000 | 443,000,000 | ||
Purchased power, affiliates | 25,000,000 | 34,000,000 | 12,000,000 | ||
Other operations and maintenance | 282,000,000 | 312,000,000 | 274,000,000 | ||
Depreciation and amortization | 198,000,000 | 157,000,000 | 126,000,000 | ||
Depreciation and amortization | 161,000,000 | 132,000,000 | 123,000,000 | ||
Taxes other than income taxes | 104,000,000 | 109,000,000 | 94,000,000 | ||
Estimated loss on Kemper IGCC | 3,362,000,000 | 428,000,000 | 365,000,000 | ||
Total operating expenses | 4,329,000,000 | 1,358,000,000 | 1,311,000,000 | ||
Operating Income | (3,142,000,000) | (195,000,000) | (173,000,000) | ||
Other Income and (Expense): | |||||
Allowance for equity funds used during construction | 72,000,000 | 124,000,000 | 110,000,000 | ||
Interest expense, net of amounts capitalized | (42,000,000) | (74,000,000) | (7,000,000) | ||
Other income (expense), net | (8,000,000) | (7,000,000) | (8,000,000) | ||
Total other income and (expense) | 22,000,000 | 43,000,000 | 95,000,000 | ||
Earnings Before Income Taxes | (3,120,000,000) | (152,000,000) | (78,000,000) | ||
Income taxes | (532,000,000) | (104,000,000) | (72,000,000) | ||
Consolidated Net Income | (2,588,000,000) | (48,000,000) | (6,000,000) | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 2,000,000 | 2,000,000 | 2,000,000 | ||
Net income after dividends on preferred and preference stock | (2,590,000,000) | (50,000,000) | (8,000,000) | ||
SOUTHERN POWER CO | |||||
Operating Revenues: | |||||
Wholesale revenues, non-affiliates | 1,671,000,000 | 1,146,000,000 | 964,000,000 | ||
Wholesale revenues, affiliates | 392,000,000 | 419,000,000 | 417,000,000 | ||
Other revenues | 12,000,000 | 12,000,000 | 9,000,000 | ||
Total operating revenues | 2,075,000,000 | 1,577,000,000 | 1,390,000,000 | ||
Operating Expenses: | |||||
Fuel | 621,000,000 | 456,000,000 | 441,000,000 | ||
Purchased power | 27,000,000 | 21,000,000 | 21,000,000 | ||
Purchased power, non-affiliates | 149,000,000 | 102,000,000 | 93,000,000 | ||
Other operations and maintenance | 386,000,000 | 354,000,000 | 260,000,000 | ||
Depreciation and amortization | 536,000,000 | 370,000,000 | 254,000,000 | ||
Depreciation and amortization | 503,000,000 | 352,000,000 | 248,000,000 | ||
Taxes other than income taxes | 48,000,000 | 23,000,000 | 22,000,000 | ||
Total operating expenses | 1,707,000,000 | 1,287,000,000 | 1,064,000,000 | ||
Operating Income | 368,000,000 | 290,000,000 | 326,000,000 | ||
Other Income and (Expense): | |||||
Interest expense, net of amounts capitalized | (191,000,000) | (117,000,000) | (77,000,000) | ||
Other income (expense), net | 1,000,000 | 6,000,000 | 1,000,000 | ||
Total other income and (expense) | (190,000,000) | (111,000,000) | (76,000,000) | ||
Earnings Before Income Taxes | 178,000,000 | 179,000,000 | 250,000,000 | ||
Income taxes | (939,000,000) | (195,000,000) | 21,000,000 | ||
Consolidated Net Income | 1,117,000,000 | 374,000,000 | 229,000,000 | ||
Less: | |||||
Net income attributable to noncontrolling interests | 46,000,000 | 36,000,000 | 14,000,000 | ||
Net income attributable to the Company | 1,071,000,000 | $ 338,000,000 | 215,000,000 | ||
SOUTHERN Co GAS | |||||
Operating Revenues: | |||||
Natural gas revenues | $ 1,596,000,000 | 3,791,000,000 | |||
Other revenues | 56,000,000 | 129,000,000 | |||
Total operating revenues | 1,652,000,000 | 3,920,000,000 | |||
Operating Expenses: | |||||
Cost of natural gas | 613,000,000 | 1,601,000,000 | |||
Cost of other sales | 10,000,000 | 29,000,000 | |||
Other operations and maintenance | 482,000,000 | 940,000,000 | |||
Depreciation and amortization | 238,000,000 | 501,000,000 | |||
Taxes other than income taxes | 71,000,000 | 184,000,000 | |||
Loss on Plant Scherer Unit 3 | 0 | ||||
Merger-related expenses | 41,000,000 | 0 | |||
Total operating expenses | 1,455,000,000 | 3,255,000,000 | |||
Operating Income | 197,000,000 | 665,000,000 | |||
Other Income and (Expense): | |||||
Earnings from equity method investments | 60,000,000 | 106,000,000 | |||
Interest expense, net of amounts capitalized | (81,000,000) | (200,000,000) | |||
Other income (expense), net | 14,000,000 | 39,000,000 | |||
Total other income and (expense) | (7,000,000) | (55,000,000) | |||
Earnings Before Income Taxes | 190,000,000 | 610,000,000 | |||
Income taxes | 76,000,000 | 367,000,000 | |||
Consolidated Net Income | 114,000,000 | 243,000,000 | |||
Less: | |||||
Net income attributable to noncontrolling interests | 0 | 0 | |||
Net income after dividends on preferred and preference stock | $ 114,000,000 | $ 243,000,000 | |||
Predecessor | SOUTHERN Co GAS | |||||
Operating Revenues: | |||||
Natural gas revenues | $ 1,841,000,000 | 3,817,000,000 | |||
Other revenues | 64,000,000 | 124,000,000 | |||
Total operating revenues | 1,905,000,000 | 3,941,000,000 | |||
Operating Expenses: | |||||
Cost of natural gas | 755,000,000 | 1,617,000,000 | |||
Cost of other sales | 14,000,000 | 28,000,000 | |||
Other operations and maintenance | 454,000,000 | 928,000,000 | |||
Depreciation and amortization | 206,000,000 | 397,000,000 | |||
Taxes other than income taxes | 99,000,000 | 181,000,000 | |||
Merger-related expenses | 56,000,000 | 44,000,000 | |||
Total operating expenses | 1,584,000,000 | 3,195,000,000 | |||
Operating Income | 321,000,000 | 746,000,000 | |||
Other Income and (Expense): | |||||
Earnings from equity method investments | 2,000,000 | 6,000,000 | |||
Interest expense, net of amounts capitalized | (96,000,000) | (175,000,000) | |||
Other income (expense), net | 5,000,000 | 9,000,000 | |||
Total other income and (expense) | (89,000,000) | (160,000,000) | |||
Earnings Before Income Taxes | 232,000,000 | 586,000,000 | |||
Income taxes | 87,000,000 | 213,000,000 | |||
Consolidated Net Income | 145,000,000 | 373,000,000 | |||
Less: | |||||
Net income attributable to noncontrolling interests | 14,000,000 | 20,000,000 | |||
Net income after dividends on preferred and preference stock | $ 131,000,000 | $ 353,000,000 |
Consolidated Statements of Inc3
Consolidated Statements of Income (Parenthetical) - SOUTHERN Co GAS - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2015 | |
Excise taxes collected | $ 32 | $ 100 | ||
Predecessor | ||||
Excise taxes collected | $ 57 | $ 103 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Consolidated Net Income | $ 926 | $ 2,529 | $ 2,435 | ||
Qualifying hedges: | |||||
Changes in fair value, net of tax | 57 | (136) | (13) | ||
Reclassification adjustment for amounts included in net income, net of tax | (60) | 69 | 6 | ||
Pension and other postretirement benefit plans: | |||||
Benefit plan net gain (loss), net of tax | 17 | 13 | (2) | ||
Reclassification adjustment for amounts included in net income, net of tax | (23) | 4 | 7 | ||
Total other comprehensive income (loss) | (9) | (50) | (2) | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 38 | 45 | 54 | ||
Comprehensive income attributable to noncontrolling interests | 46 | 36 | 14 | ||
Comprehensive Income | 833 | 2,398 | 2,365 | ||
ALABAMA POWER CO | |||||
Consolidated Net Income | 866 | 839 | 811 | ||
Qualifying hedges: | |||||
Changes in fair value, net of tax | 1 | (2) | (5) | ||
Reclassification adjustment for amounts included in net income, net of tax | 3 | 4 | 2 | ||
Pension and other postretirement benefit plans: | |||||
Total other comprehensive income (loss) | 4 | 2 | (3) | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 18 | 17 | 26 | ||
Comprehensive Income | 870 | 841 | 808 | ||
GEORGIA POWER CO | |||||
Consolidated Net Income | 1,428 | 1,347 | 1,277 | ||
Qualifying hedges: | |||||
Changes in fair value, net of tax | 0 | 0 | (9) | ||
Reclassification adjustment for amounts included in net income, net of tax | 3 | 2 | 2 | ||
Pension and other postretirement benefit plans: | |||||
Total other comprehensive income (loss) | 3 | 2 | (7) | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 14 | 17 | 17 | ||
Comprehensive Income | 1,431 | 1,349 | 1,270 | ||
GULF POWER CO | |||||
Consolidated Net Income | 139 | 140 | 157 | ||
Qualifying hedges: | |||||
Changes in fair value, net of tax | (1) | 1 | 1 | ||
Pension and other postretirement benefit plans: | |||||
Total other comprehensive income (loss) | (1) | 1 | 1 | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 4 | 9 | 9 | ||
Comprehensive Income | 138 | 141 | 158 | ||
MISSISSIPPI POWER CO | |||||
Consolidated Net Income | (2,588) | (48) | (6) | ||
Qualifying hedges: | |||||
Changes in fair value, net of tax | (1) | 1 | 0 | ||
Reclassification adjustment for amounts included in net income, net of tax | 1 | 1 | 1 | ||
Pension and other postretirement benefit plans: | |||||
Total other comprehensive income (loss) | 0 | 2 | 1 | ||
Less: | |||||
Dividends on preferred and preference stock of subsidiaries | 2 | 2 | 2 | ||
Comprehensive Income | (2,588) | (46) | (5) | ||
SOUTHERN POWER CO | |||||
Consolidated Net Income | 1,117 | 374 | 229 | ||
Qualifying hedges: | |||||
Changes in fair value, net of tax | 63 | (27) | 0 | ||
Reclassification adjustment for amounts included in net income, net of tax | (73) | 58 | 1 | ||
Pension and other postretirement benefit plans: | |||||
Total other comprehensive income (loss) | (10) | 31 | 1 | ||
Less: | |||||
Comprehensive income attributable to noncontrolling interests | 46 | 36 | 14 | ||
Comprehensive Income | 1,061 | $ 369 | 216 | ||
SOUTHERN Co GAS | |||||
Consolidated Net Income | $ 114 | 243 | |||
Qualifying hedges: | |||||
Changes in fair value, net of tax | (1) | (5) | |||
Reclassification adjustment for amounts included in net income, net of tax | 0 | 1 | |||
Pension and other postretirement benefit plans: | |||||
Benefit plan net gain (loss), net of tax | 27 | (1) | |||
Reclassification adjustment for amounts included in net income, net of tax | 0 | 0 | |||
Total other comprehensive income (loss) | 26 | (5) | |||
Less: | |||||
Comprehensive income attributable to noncontrolling interests | 0 | 0 | |||
Comprehensive Income | $ 140 | $ 238 | |||
Predecessor | SOUTHERN Co GAS | |||||
Consolidated Net Income | $ 145 | 373 | |||
Qualifying hedges: | |||||
Changes in fair value, net of tax | (41) | 0 | |||
Reclassification adjustment for amounts included in net income, net of tax | 1 | 8 | |||
Pension and other postretirement benefit plans: | |||||
Benefit plan net gain (loss), net of tax | 0 | 0 | |||
Reclassification adjustment for amounts included in net income, net of tax | 5 | 12 | |||
Total other comprehensive income (loss) | (35) | 20 | |||
Less: | |||||
Comprehensive income attributable to noncontrolling interests | 14 | 20 | |||
Comprehensive Income | $ 96 | $ 373 |
Consolidated Statements of Com5
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Qualifying hedges change in fair value tax | $ 34 | $ (84) | $ (8) | ||
Qualifying hedges reclassification adjustment tax | (37) | 43 | 4 | ||
Pension and other postretirement benefit plans gain (loss) tax | 6 | 10 | (1) | ||
Pension and other postretirement benefit plans reclassification adjustment tax | (6) | 3 | 4 | ||
ALABAMA POWER CO | |||||
Qualifying hedges change in fair value tax | (1) | (1) | (3) | ||
Qualifying hedges reclassification adjustment tax | 2 | 2 | 1 | ||
GEORGIA POWER CO | |||||
Qualifying hedges change in fair value tax | 0 | 0 | (6) | ||
Qualifying hedges reclassification adjustment tax | 1 | 2 | 1 | ||
GULF POWER CO | |||||
Qualifying hedges change in fair value tax | (1) | 0 | 0 | ||
MISSISSIPPI POWER CO | |||||
Qualifying hedges change in fair value tax | (1) | 1 | 0 | ||
Qualifying hedges reclassification adjustment tax | 1 | 1 | 1 | ||
SOUTHERN POWER CO | |||||
Qualifying hedges change in fair value tax | 39 | (17) | 0 | ||
Qualifying hedges reclassification adjustment tax | (46) | $ 36 | 0 | ||
SOUTHERN Co GAS | |||||
Qualifying hedges change in fair value tax | $ (1) | (3) | |||
Qualifying hedges reclassification adjustment tax | 0 | 0 | |||
Pension and other postretirement benefit plans gain (loss) tax | 19 | 0 | |||
Pension and other postretirement benefit plans reclassification adjustment tax | $ 0 | $ 0 | |||
Predecessor | SOUTHERN Co GAS | |||||
Qualifying hedges change in fair value tax | $ (23) | (3) | |||
Qualifying hedges reclassification adjustment tax | 0 | 1 | |||
Pension and other postretirement benefit plans gain (loss) tax | 0 | 0 | |||
Pension and other postretirement benefit plans reclassification adjustment tax | $ (4) | $ (9) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating Activities: | |||
Consolidated net income | $ 926,000,000 | $ 2,529,000,000 | $ 2,435,000,000 |
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 3,457,000,000 | 2,923,000,000 | 2,395,000,000 |
Deferred income taxes | 166,000,000 | (127,000,000) | 1,404,000,000 |
Amortization of investment tax credits | (22,000,000) | (22,000,000) | (21,000,000) |
Collateral deposits | (4,000,000) | (102,000,000) | 0 |
Allowance for equity funds used during construction | (160,000,000) | (202,000,000) | (226,000,000) |
Pension and postretirement funding | (2,000,000) | (1,029,000,000) | (7,000,000) |
Settlement of asset retirement obligations | (177,000,000) | (171,000,000) | (37,000,000) |
Stock based compensation expense | 109,000,000 | 121,000,000 | 99,000,000 |
Hedge settlements | 6,000,000 | (233,000,000) | (17,000,000) |
Estimated Loss On Integrated Coal Gasification Combined Cycle Project, Non-Cash | 3,179,000,000 | 428,000,000 | 365,000,000 |
Income taxes receivable, non-current | (47,000,000) | (122,000,000) | (413,000,000) |
Other, net | (109,000,000) | (99,000,000) | 49,000,000 |
Changes in certain current assets and liabilities — | |||
-Receivables | (199,000,000) | (544,000,000) | 243,000,000 |
-Fossil fuel for generation | 36,000,000 | 178,000,000 | 61,000,000 |
-Natural gas for sale | 36,000,000 | (226,000,000) | 0 |
-Other current assets | (143,000,000) | (206,000,000) | (152,000,000) |
-Accounts payable | (280,000,000) | 301,000,000 | (353,000,000) |
-Accrued taxes | (142,000,000) | 1,456,000,000 | 352,000,000 |
-Retail fuel cost over recovery | (212,000,000) | (231,000,000) | 289,000,000 |
-Mirror CWIP | 0 | 0 | (271,000,000) |
-Other current liabilities | (45,000,000) | 250,000,000 | 58,000,000 |
Net cash provided from operating activities | 6,395,000,000 | 4,894,000,000 | 6,274,000,000 |
Investing Activities: | |||
Business acquisitions, net of cash acquired | (1,070,000,000) | (10,689,000,000) | (1,719,000,000) |
Property additions | (7,423,000,000) | (7,310,000,000) | (5,674,000,000) |
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion | 1,682,000,000 | 0 | 0 |
Investment in restricted cash | (17,000,000) | (733,000,000) | (160,000,000) |
Distribution of restricted cash | 34,000,000 | 742,000,000 | 154,000,000 |
Nuclear decommissioning trust fund purchases | (811,000,000) | (1,160,000,000) | (1,424,000,000) |
Nuclear decommissioning trust fund sales | 805,000,000 | 1,154,000,000 | 1,418,000,000 |
Cost of removal, net of salvage | (313,000,000) | (245,000,000) | (167,000,000) |
Change in construction payables, net | 259,000,000 | (121,000,000) | 402,000,000 |
Investment in unconsolidated subsidiaries | (152,000,000) | (1,444,000,000) | 0 |
Payments pursuant to LTSAs | (227,000,000) | (134,000,000) | (197,000,000) |
Other investing activities | 42,000,000 | (108,000,000) | 87,000,000 |
Net cash used for investing activities | (7,191,000,000) | (20,048,000,000) | (7,280,000,000) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | (401,000,000) | 1,228,000,000 | 73,000,000 |
Proceeds — | |||
Long-term debt | 5,858,000,000 | 16,368,000,000 | 7,029,000,000 |
Common stock | 793,000,000 | 3,758,000,000 | 256,000,000 |
Preferred stock | 250,000,000 | 0 | 0 |
Short-term borrowings | 1,259,000,000 | 0 | 755,000,000 |
Redemptions and repurchases — | |||
Long-term debt | (2,930,000,000) | (3,145,000,000) | (3,604,000,000) |
Common stock | 0 | 0 | (115,000,000) |
Interest-bearing refundable deposits | 0 | 0 | (275,000,000) |
Preferred and preference stock | (658,000,000) | 0 | (412,000,000) |
Short-term borrowings | (659,000,000) | (478,000,000) | (255,000,000) |
Distributions to noncontrolling interests | (119,000,000) | (72,000,000) | (18,000,000) |
Capital contributions from noncontrolling interests | 80,000,000 | 682,000,000 | 341,000,000 |
Purchase of membership interests from noncontrolling interests | 0 | 0 | 0 |
Payment of common stock dividends | (2,300,000,000) | (2,104,000,000) | (1,959,000,000) |
Other financing activities | (222,000,000) | (512,000,000) | (116,000,000) |
Net cash provided from financing activities | 951,000,000 | 15,725,000,000 | 1,700,000,000 |
Net Change in Cash and Cash Equivalents | 155,000,000 | 571,000,000 | 694,000,000 |
Cash and Cash Equivalents at Beginning of Year | 1,975,000,000 | 1,404,000,000 | 710,000,000 |
Cash and Cash Equivalents at End of Year | 2,130,000,000 | 1,975,000,000 | 1,404,000,000 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 1,700,000,000 | 1,100,000,000 | 809,000,000 |
Income taxes (net of refunds) | (410,000,000) | (148,000,000) | (9,000,000) |
Noncash transactions - | |||
Accrued property additions at year-end | 985,000,000 | 1,300,000,000 | 844,000,000 |
ALABAMA POWER CO | |||
Operating Activities: | |||
Consolidated net income | 866,000,000 | 839,000,000 | 811,000,000 |
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 888,000,000 | 844,000,000 | 780,000,000 |
Deferred income taxes | 409,000,000 | 407,000,000 | 388,000,000 |
Amortization of investment tax credits | (7,000,000) | (8,000,000) | (8,000,000) |
Allowance for equity funds used during construction | (39,000,000) | (28,000,000) | (60,000,000) |
Pension and postretirement funding | (2,000,000) | (133,000,000) | 0 |
Other, net | (14,000,000) | (102,000,000) | 15,000,000 |
Changes in certain current assets and liabilities — | |||
-Receivables | (168,000,000) | 94,000,000 | (160,000,000) |
-Other current assets | (16,000,000) | 1,000,000 | 40,000,000 |
-Accounts payable | 71,000,000 | 73,000,000 | 3,000,000 |
-Accrued taxes | (84,000,000) | 93,000,000 | 138,000,000 |
-Retail fuel cost over recovery | (76,000,000) | (162,000,000) | 191,000,000 |
-Other current liabilities | 2,000,000 | 23,000,000 | (4,000,000) |
Net cash provided from operating activities | 1,837,000,000 | 1,949,000,000 | 2,142,000,000 |
Investing Activities: | |||
Property additions | (1,882,000,000) | (1,272,000,000) | (1,367,000,000) |
Nuclear decommissioning trust fund purchases | (237,000,000) | (352,000,000) | (439,000,000) |
Nuclear decommissioning trust fund sales | 237,000,000 | 351,000,000 | 438,000,000 |
Cost of removal, net of salvage | (112,000,000) | (94,000,000) | (71,000,000) |
Change in construction payables, net | 161,000,000 | (37,000,000) | (15,000,000) |
Other investing activities | (43,000,000) | (34,000,000) | (34,000,000) |
Net cash used for investing activities | (1,876,000,000) | (1,438,000,000) | (1,488,000,000) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | 3,000,000 | 0 | 0 |
Proceeds — | |||
Preferred stock | 250,000,000 | 0 | 0 |
Senior notes | 1,100,000,000 | 400,000,000 | 975,000,000 |
Pollution control revenue bonds | 0 | 0 | 80,000,000 |
Other long-term debt | 0 | 45,000,000 | 0 |
Capital contributions from parent company | 361,000,000 | 260,000,000 | 22,000,000 |
Redemptions and repurchases — | |||
Preferred and preference stock | (238,000,000) | 0 | (412,000,000) |
Senior notes | (525,000,000) | (200,000,000) | (650,000,000) |
Pollution control revenue bonds | (36,000,000) | 0 | (134,000,000) |
Payment of common stock dividends | (714,000,000) | (765,000,000) | (571,000,000) |
Other financing activities | (38,000,000) | (25,000,000) | (43,000,000) |
Net cash provided from financing activities | 163,000,000 | (285,000,000) | (733,000,000) |
Net Change in Cash and Cash Equivalents | 124,000,000 | 226,000,000 | (79,000,000) |
Cash and Cash Equivalents at Beginning of Year | 420,000,000 | 194,000,000 | 273,000,000 |
Cash and Cash Equivalents at End of Year | 544,000,000 | 420,000,000 | 194,000,000 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 285,000,000 | 277,000,000 | 250,000,000 |
Income taxes (net of refunds) | 236,000,000 | (108,000,000) | 121,000,000 |
Noncash transactions - | |||
Accrued property additions at year-end | 245,000,000 | 84,000,000 | 121,000,000 |
GEORGIA POWER CO | |||
Operating Activities: | |||
Consolidated net income | 1,428,000,000 | 1,347,000,000 | 1,277,000,000 |
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 1,100,000,000 | 1,063,000,000 | 1,029,000,000 |
Deferred income taxes | 458,000,000 | 383,000,000 | 173,000,000 |
Amortization of investment tax credits | (10,000,000) | (10,000,000) | (10,000,000) |
Pension, postretirement, and other employee benefits | (68,000,000) | (33,000,000) | 40,000,000 |
Retail fuel cost-recovery - long-term | 0 | 0 | 106,000,000 |
Pension and postretirement funding | 0 | (287,000,000) | (7,000,000) |
Settlement of asset retirement obligations | (120,000,000) | (123,000,000) | (29,000,000) |
Other deferred charges - affiliated | 0 | (111,000,000) | 0 |
Other, net | (83,000,000) | (25,000,000) | (70,000,000) |
Changes in certain current assets and liabilities — | |||
-Receivables | (256,000,000) | 60,000,000 | 187,000,000 |
-Fossil fuel for generation | (16,000,000) | 104,000,000 | 37,000,000 |
-Prepaid income taxes | (168,000,000) | 0 | 89,000,000 |
-Other current assets | (28,000,000) | (38,000,000) | (62,000,000) |
-Accounts payable | (219,000,000) | (42,000,000) | (259,000,000) |
-Accrued taxes | 1,000,000 | 131,000,000 | 25,000,000 |
-Retail fuel cost over recovery | (84,000,000) | (32,000,000) | 10,000,000 |
-Other current liabilities | (33,000,000) | 28,000,000 | (29,000,000) |
Net cash provided from operating activities | 1,912,000,000 | 2,425,000,000 | 2,517,000,000 |
Investing Activities: | |||
Property additions | (2,704,000,000) | (2,223,000,000) | (2,091,000,000) |
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion | 1,682,000,000 | 0 | 0 |
Nuclear decommissioning trust fund purchases | (574,000,000) | (808,000,000) | (985,000,000) |
Nuclear decommissioning trust fund sales | 568,000,000 | 803,000,000 | 980,000,000 |
Cost of removal, net of salvage | (100,000,000) | (83,000,000) | (71,000,000) |
Change in construction payables, net of joint owner portion | 223,000,000 | (35,000,000) | 217,000,000 |
Payments pursuant to LTSAs | (64,000,000) | (34,000,000) | (66,000,000) |
Sale of property | 96,000,000 | 10,000,000 | 70,000,000 |
Other investing activities | (39,000,000) | 23,000,000 | 2,000,000 |
Net cash used for investing activities | (912,000,000) | (2,347,000,000) | (1,944,000,000) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | (391,000,000) | 234,000,000 | 2,000,000 |
Proceeds — | |||
Short-term borrowings | 700,000,000 | 0 | 250,000,000 |
Senior notes | 1,350,000,000 | 650,000,000 | 500,000,000 |
Pollution control revenue bonds | 65,000,000 | 0 | 409,000,000 |
Other long-term debt | 370,000,000 | 0 | 0 |
Capital contributions from parent company | 431,000,000 | 594,000,000 | 62,000,000 |
FFB loan | 0 | 425,000,000 | 1,000,000,000 |
Redemptions and repurchases — | |||
Preferred and preference stock | (270,000,000) | 0 | 0 |
Short-term borrowings | (550,000,000) | 0 | (250,000,000) |
Senior notes | (450,000,000) | (700,000,000) | (1,175,000,000) |
Pollution control revenue bonds | (65,000,000) | (4,000,000) | (268,000,000) |
Payment of common stock dividends | (1,281,000,000) | (1,305,000,000) | (1,034,000,000) |
Other financing activities | (60,000,000) | (36,000,000) | (26,000,000) |
Net cash provided from financing activities | (151,000,000) | (142,000,000) | (530,000,000) |
Net Change in Cash and Cash Equivalents | 849,000,000 | (64,000,000) | 43,000,000 |
Cash and Cash Equivalents at Beginning of Year | 3,000,000 | 67,000,000 | 24,000,000 |
Cash and Cash Equivalents at End of Year | 852,000,000 | 3,000,000 | 67,000,000 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 386,000,000 | 375,000,000 | 353,000,000 |
Income taxes (net of refunds) | 496,000,000 | 170,000,000 | 506,000,000 |
Noncash transactions - | |||
Accrued property additions at year-end | 550,000,000 | 336,000,000 | 387,000,000 |
Capital lease obligation | 0 | 0 | 149,000,000 |
GULF POWER CO | |||
Operating Activities: | |||
Consolidated net income | 139,000,000 | 140,000,000 | 157,000,000 |
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 149,000,000 | 179,000,000 | 152,000,000 |
Deferred income taxes | 72,000,000 | 57,000,000 | 90,000,000 |
Pension and postretirement funding | 0 | (48,000,000) | 0 |
Loss on Plant Scherer Unit 3 | 33,000,000 | 0 | 0 |
Other, net | (3,000,000) | (3,000,000) | 4,000,000 |
Changes in certain current assets and liabilities — | |||
-Receivables | (43,000,000) | 15,000,000 | 33,000,000 |
-Fossil fuel for generation | 8,000,000 | 37,000,000 | (6,000,000) |
-Prepaid income taxes | 8,000,000 | (11,000,000) | 32,000,000 |
-Other current assets | (2,000,000) | (1,000,000) | (2,000,000) |
-Accounts payable | 20,000,000 | 5,000,000 | (22,000,000) |
-Over recovered regulatory clause revenues | (12,000,000) | 1,000,000 | 22,000,000 |
-Other current liabilities | (13,000,000) | 8,000,000 | 0 |
Net cash provided from operating activities | 356,000,000 | 379,000,000 | 460,000,000 |
Investing Activities: | |||
Property additions | (202,000,000) | (178,000,000) | (235,000,000) |
Cost of removal, net of salvage | (21,000,000) | (9,000,000) | (10,000,000) |
Change in construction payables, net | (2,000,000) | 13,000,000 | (28,000,000) |
Other investing activities | (9,000,000) | (6,000,000) | (8,000,000) |
Net cash used for investing activities | (234,000,000) | (180,000,000) | (281,000,000) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | (223,000,000) | 126,000,000 | 32,000,000 |
Proceeds — | |||
Common stock | 175,000,000 | 0 | 20,000,000 |
Senior notes | 300,000,000 | 0 | 0 |
Pollution control revenue bonds | 0 | 0 | 13,000,000 |
Capital contributions from parent company | 2,000,000 | 20,000,000 | 4,000,000 |
Redemptions and repurchases — | |||
Preferred and preference stock | (150,000,000) | 0 | 0 |
Senior notes | (85,000,000) | (235,000,000) | (60,000,000) |
Pollution control revenue bonds | 0 | 0 | (13,000,000) |
Payment of common stock dividends | (165,000,000) | (120,000,000) | (130,000,000) |
Other financing activities | (4,000,000) | (8,000,000) | (10,000,000) |
Net cash provided from financing activities | (150,000,000) | (217,000,000) | (144,000,000) |
Net Change in Cash and Cash Equivalents | (28,000,000) | (18,000,000) | 35,000,000 |
Cash and Cash Equivalents at Beginning of Year | 56,000,000 | 74,000,000 | 39,000,000 |
Cash and Cash Equivalents at End of Year | 28,000,000 | 56,000,000 | 74,000,000 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 46,000,000 | 53,000,000 | 52,000,000 |
Income taxes (net of refunds) | 12,000,000 | 21,000,000 | (7,000,000) |
Noncash transactions - | |||
Accrued property additions at year-end | 31,000,000 | 33,000,000 | 20,000,000 |
Receivables related to energy services | (7,000,000) | 0 | 0 |
Receivables Related to Energy Services | 7,000,000 | 0 | 0 |
MISSISSIPPI POWER CO | |||
Operating Activities: | |||
Consolidated net income | (2,588,000,000) | (48,000,000) | (6,000,000) |
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 198,000,000 | 157,000,000 | 126,000,000 |
Deferred income taxes | (727,000,000) | (67,000,000) | 777,000,000 |
Investment tax credits | 0 | 0 | (210,000,000) |
Amortization of investment tax credits | (1,000,000) | (1,000,000) | (1,000,000) |
Allowance for equity funds used during construction | (72,000,000) | (124,000,000) | (110,000,000) |
Pension and postretirement funding | 0 | (47,000,000) | 0 |
Regulatory assets associated with Kemper IGCC | (19,000,000) | (12,000,000) | (61,000,000) |
Estimated Loss On Integrated Coal Gasification Combined Cycle Project, Non-Cash | 3,179,000,000 | 428,000,000 | 365,000,000 |
Income taxes receivable, non-current | 0 | 0 | (544,000,000) |
Other, net | (12,000,000) | (20,000,000) | 8,000,000 |
Changes in certain current assets and liabilities — | |||
-Receivables | 540,000,000 | 13,000,000 | 28,000,000 |
-Fossil fuel for generation | 24,000,000 | 4,000,000 | (4,000,000) |
-Prepaid income taxes | 0 | 39,000,000 | (35,000,000) |
-Other current assets | (13,000,000) | (12,000,000) | (14,000,000) |
-Accounts payable | (3,000,000) | (14,000,000) | (34,000,000) |
Increase (decrease) in interest payable, net | (29,000,000) | 27,000,000 | (2,000,000) |
-Accrued taxes | 80,000,000 | 14,000,000 | (11,000,000) |
-Over recovered regulatory clause revenues | (51,000,000) | (45,000,000) | 96,000,000 |
-Mirror CWIP | 0 | 0 | (271,000,000) |
-Customer liability associated with Kemper refunds | (1,000,000) | (73,000,000) | 73,000,000 |
-Other current liabilities | (3,000,000) | 9,000,000 | 2,000,000 |
Net cash provided from operating activities | 503,000,000 | 229,000,000 | 173,000,000 |
Investing Activities: | |||
Property additions | (429,000,000) | (798,000,000) | (857,000,000) |
Change in construction payables, net | (47,000,000) | (26,000,000) | (9,000,000) |
Government grant proceeds | 0 | 137,000,000 | 0 |
Other investing activities | (28,000,000) | (10,000,000) | (40,000,000) |
Net cash used for investing activities | (504,000,000) | (697,000,000) | (906,000,000) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | (18,000,000) | 0 | 0 |
Proceeds — | |||
Short-term borrowings | 109,000,000 | 0 | 505,000,000 |
Other long-term debt | 0 | 1,200,000,000 | 0 |
Capital contributions from parent company | 1,002,000,000 | 627,000,000 | 277,000,000 |
Long-term debt issuance to parent company | 40,000,000 | 200,000,000 | 275,000,000 |
Redemptions and repurchases — | |||
Short-term borrowings | (109,000,000) | (478,000,000) | (5,000,000) |
Senior notes | (35,000,000) | (300,000,000) | 0 |
Long-term debt redemption to parent company | (591,000,000) | (225,000,000) | 0 |
Other long-term debt | (300,000,000) | (425,000,000) | (350,000,000) |
Other financing activities | (2,000,000) | (2,000,000) | (1,000,000) |
Repayments of long-term capital lease obligations | 71,000,000 | 3,000,000 | 3,000,000 |
Net cash provided from financing activities | 25,000,000 | 594,000,000 | 698,000,000 |
Net Change in Cash and Cash Equivalents | 24,000,000 | 126,000,000 | (35,000,000) |
Cash and Cash Equivalents at Beginning of Year | 224,000,000 | 98,000,000 | 133,000,000 |
Cash and Cash Equivalents at End of Year | 248,000,000 | 224,000,000 | 98,000,000 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 65,000,000 | 50,000,000 | 45,000,000 |
Income taxes (net of refunds) | (424,000,000) | (97,000,000) | (33,000,000) |
Noncash transactions - | |||
Accrued property additions at year-end | 32,000,000 | 78,000,000 | 105,000,000 |
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | 0 | 0 | 301,000,000 |
SOUTHERN POWER CO | |||
Operating Activities: | |||
Consolidated net income | 1,117,000,000 | 374,000,000 | 229,000,000 |
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 536,000,000 | 370,000,000 | 254,000,000 |
Deferred income taxes | (263,000,000) | (1,063,000,000) | 42,000,000 |
Investment tax credits | 0 | 0 | 162,000,000 |
Amortization of investment tax credits | (57,000,000) | (37,000,000) | (19,000,000) |
Collateral deposits | (4,000,000) | (102,000,000) | 0 |
Income taxes receivable, non-current | (61,000,000) | (13,000,000) | 0 |
Accrued income taxes, non-current | 14,000,000 | (109,000,000) | 109,000,000 |
Other, net | (9,000,000) | 12,000,000 | (2,000,000) |
Changes in certain current assets and liabilities — | |||
-Receivables | (60,000,000) | (54,000,000) | 18,000,000 |
-Other current assets | (4,000,000) | (25,000,000) | (30,000,000) |
-Accrued taxes | (55,000,000) | 940,000,000 | 269,000,000 |
-Other current liabilities | 1,000,000 | 46,000,000 | (29,000,000) |
Net cash provided from operating activities | 1,155,000,000 | 339,000,000 | 1,003,000,000 |
Investing Activities: | |||
Business acquisitions, net of cash acquired | (1,032,000,000) | (2,294,000,000) | (1,719,000,000) |
Property additions | (268,000,000) | (2,114,000,000) | (1,005,000,000) |
Investment in restricted cash | (16,000,000) | (733,000,000) | (159,000,000) |
Distribution of restricted cash | 34,000,000 | 736,000,000 | 154,000,000 |
Change in construction payables, net of joint owner portion | (153,000,000) | (57,000,000) | 251,000,000 |
Payments pursuant to long-term service agreements | (203,000,000) | (350,000,000) | (82,000,000) |
Other investing activities | 15,000,000 | 15,000,000 | 22,000,000 |
Net cash used for investing activities | (1,623,000,000) | (4,797,000,000) | (2,538,000,000) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | (104,000,000) | 73,000,000 | (58,000,000) |
Proceeds — | |||
Senior notes | 525,000,000 | 2,831,000,000 | 1,650,000,000 |
Other long-term debt | 43,000,000 | 65,000,000 | 402,000,000 |
Capital contributions from parent company | 0 | 1,850,000,000 | 646,000,000 |
Redemptions and repurchases — | |||
Senior notes | (500,000,000) | (200,000,000) | (525,000,000) |
Other long-term debt | (18,000,000) | (86,000,000) | (4,000,000) |
Distributions to noncontrolling interests | (119,000,000) | (57,000,000) | (18,000,000) |
Capital contributions from noncontrolling interests | 80,000,000 | 682,000,000 | 341,000,000 |
Purchase of membership interests from noncontrolling interests | (59,000,000) | (129,000,000) | 0 |
Payment of common stock dividends | (317,000,000) | (272,000,000) | (131,000,000) |
Other financing activities | (33,000,000) | (30,000,000) | (13,000,000) |
Net cash provided from financing activities | (502,000,000) | 4,727,000,000 | 2,290,000,000 |
Net Change in Cash and Cash Equivalents | (970,000,000) | 269,000,000 | 755,000,000 |
Cash and Cash Equivalents at Beginning of Year | 1,099,000,000 | 830,000,000 | 75,000,000 |
Cash and Cash Equivalents at End of Year | 129,000,000 | 1,099,000,000 | 830,000,000 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 189,000,000 | 89,000,000 | 74,000,000 |
Income taxes (net of refunds) | (487,000,000) | 116,000,000 | (518,000,000) |
Noncash transactions - | |||
Accrued property additions at year-end | 32,000,000 | 251,000,000 | 257,000,000 |
Acquisitions | 0 | 461,000,000 | 0 |
SOUTHERN Co GAS | |||
Operating Activities: | |||
Consolidated net income | 243,000,000 | ||
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 501,000,000 | ||
Deferred income taxes | 236,000,000 | ||
Amortization of investment tax credits | (4,000,000) | ||
Pension, postretirement, and other employee benefits | (1,000,000) | ||
Pension and postretirement funding | 0 | ||
Loss on Plant Scherer Unit 3 | 0 | ||
Stock based compensation expense | 32,000,000 | ||
Hedge settlements | 0 | ||
Goodwill impairment | 0 | ||
Mark-to-market adjustments | (24,000,000) | ||
Other, net | (83,000,000) | ||
Changes in certain current assets and liabilities — | |||
-Receivables | (91,000,000) | ||
-Prepaid income taxes | (39,000,000) | ||
-Natural gas for sale | 36,000,000 | ||
-Other current assets | (24,000,000) | ||
-Accounts payable | (20,000,000) | ||
-Accrued taxes | 110,000,000 | ||
-Accrued compensation | 15,000,000 | ||
Other current liabilities | (8,000,000) | ||
Net cash provided from operating activities | 883,000,000 | ||
Investing Activities: | |||
Property additions | (1,514,000,000) | ||
Cost of removal, net of salvage | (66,000,000) | ||
Change in construction payables, net | 72,000,000 | ||
Investment in unconsolidated subsidiaries | (145,000,000) | ||
Returned investment in unconsolidated subsidiaries | 80,000,000 | ||
Other investing activities | 3,000,000 | ||
Net cash used for investing activities | (1,570,000,000) | ||
Financing Activities: | |||
Increase (decrease) in notes payable, net | 262,000,000 | ||
Proceeds — | |||
First mortgage bonds | 400,000,000 | ||
Senior notes | 450,000,000 | ||
Capital contributions from parent company | 103,000,000 | ||
Redemptions and repurchases — | |||
Medium-term notes | (22,000,000) | ||
Senior notes | 0 | ||
First mortgage bonds | 0 | ||
Distributions to noncontrolling interests | 0 | ||
Purchase of 15% noncontrolling interest in SouthStar | 0 | ||
Payment of common stock dividends | (443,000,000) | ||
Other financing activities | (9,000,000) | ||
Net cash provided from financing activities | 741,000,000 | ||
Net Change in Cash and Cash Equivalents | 54,000,000 | ||
Cash and Cash Equivalents at Beginning of Year | 19,000,000 | ||
Cash and Cash Equivalents at End of Year | 73,000,000 | 19,000,000 | |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 223,000,000 | ||
Income taxes (net of refunds) | 72,000,000 | ||
Noncash transactions - | |||
Accrued property additions at year-end | $ 135,000,000 | ||
Predecessor | SOUTHERN Co GAS | |||
Operating Activities: | |||
Consolidated net income | 373,000,000 | ||
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||
Depreciation and amortization, total | 397,000,000 | ||
Deferred income taxes | 211,000,000 | ||
Amortization of investment tax credits | (2,000,000) | ||
Pension, postretirement, and other employee benefits | 24,000,000 | ||
Pension and postretirement funding | 0 | ||
Stock based compensation expense | 34,000,000 | ||
Hedge settlements | 0 | ||
Goodwill impairment | 14,000,000 | ||
Mark-to-market adjustments | 22,000,000 | ||
Other, net | 43,000,000 | ||
Changes in certain current assets and liabilities — | |||
-Receivables | 615,000,000 | ||
-Prepaid income taxes | 23,000,000 | ||
-Natural gas for sale | 72,000,000 | ||
-Other current assets | (11,000,000) | ||
-Accounts payable | (434,000,000) | ||
-Accrued taxes | (20,000,000) | ||
-Accrued compensation | (6,000,000) | ||
Other current liabilities | 24,000,000 | ||
Net cash provided from operating activities | 1,381,000,000 | ||
Investing Activities: | |||
Property additions | (961,000,000) | ||
Cost of removal, net of salvage | (84,000,000) | ||
Change in construction payables, net | 18,000,000 | ||
Investment in unconsolidated subsidiaries | (12,000,000) | ||
Returned investment in unconsolidated subsidiaries | 12,000,000 | ||
Other investing activities | 0 | ||
Net cash used for investing activities | (1,027,000,000) | ||
Financing Activities: | |||
Increase (decrease) in notes payable, net | (165,000,000) | ||
Proceeds — | |||
First mortgage bonds | 0 | ||
Senior notes | 250,000,000 | ||
Capital contributions from parent company | 0 | ||
Redemptions and repurchases — | |||
Medium-term notes | 0 | ||
Senior notes | (200,000,000) | ||
First mortgage bonds | 0 | ||
Distributions to noncontrolling interests | (18,000,000) | ||
Purchase of 15% noncontrolling interest in SouthStar | 0 | ||
Payment of common stock dividends | (244,000,000) | ||
Other financing activities | 11,000,000 | ||
Net cash provided from financing activities | (366,000,000) | ||
Net Change in Cash and Cash Equivalents | (12,000,000) | ||
Cash and Cash Equivalents at Beginning of Year | 19,000,000 | 31,000,000 | |
Cash and Cash Equivalents at End of Year | 19,000,000 | ||
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | $ 181,000,000 | ||
Income taxes (net of refunds) | (26,000,000) | ||
Noncash transactions - | |||
Accrued property additions at year-end | $ 48,000,000 |
Consolidated Statements of Cas7
Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Net cash paid for capitalized interest | $ 89 | $ 125 | $ 124 | |
ALABAMA POWER CO | ||||
Net cash paid for capitalized interest | 15 | 11 | 22 | |
GEORGIA POWER CO | ||||
Net cash paid for capitalized interest | 23 | 20 | 16 | |
GULF POWER CO | ||||
Net cash paid for capitalized interest | 0 | 0 | 6 | |
MISSISSIPPI POWER CO | ||||
Net cash paid for capitalized interest | 29 | 49 | 66 | |
SOUTHERN POWER CO | ||||
Net cash paid for capitalized interest | $ 11 | $ 44 | $ 14 | |
SOUTHERN Co GAS | Southstar | ||||
Ownership percentage of noncontrolling interest | 15.00% |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets: | ||
Cash and cash equivalents | $ 2,130,000,000 | $ 1,975,000,000 |
Receivables — | ||
Customer accounts receivable | 1,806,000,000 | 1,583,000,000 |
Energy marketing receivable | 607,000,000 | 623,000,000 |
Unbilled revenues | 810,000,000 | 706,000,000 |
Under recovered fuel clause revenues | 171,000,000 | 0 |
Income taxes receivable, current | 63,000,000 | 544,000,000 |
Other accounts and notes receivable | 635,000,000 | 377,000,000 |
Accumulated provision for uncollectible accounts | (44,000,000) | (43,000,000) |
Materials and supplies | 1,438,000,000 | 1,462,000,000 |
Fossil fuel for generation | 594,000,000 | 689,000,000 |
Natural gas for sale | 595,000,000 | 631,000,000 |
Prepaid expenses | 452,000,000 | 364,000,000 |
Other regulatory assets, current | 604,000,000 | 581,000,000 |
Other current assets | 211,000,000 | 230,000,000 |
Total current assets | 10,072,000,000 | 9,722,000,000 |
Property, Plant, and Equipment: | ||
In service | 103,542,000,000 | 98,416,000,000 |
Less: Accumulated depreciation | 31,457,000,000 | 29,852,000,000 |
Plant in service, net of depreciation | 72,085,000,000 | 68,564,000,000 |
Nuclear fuel, at amortized cost | 883,000,000 | 905,000,000 |
Construction work in progress | 6,904,000,000 | 8,977,000,000 |
Total property, plant, and equipment | 79,872,000,000 | 78,446,000,000 |
Other Property and Investments: | ||
Goodwill | 6,268,000,000 | 6,251,000,000 |
Equity investments in unconsolidated subsidiaries | 1,513,000,000 | 1,549,000,000 |
Other intangible assets, net of amortization | 873,000,000 | 970,000,000 |
Nuclear decommissioning trusts, at fair value | 1,832,000,000 | 1,606,000,000 |
Leveraged leases | 775,000,000 | 774,000,000 |
Miscellaneous property and investments | 249,000,000 | 270,000,000 |
Total other property and investments | 11,510,000,000 | 11,420,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 825,000,000 | 1,629,000,000 |
Unamortized loss on reacquired debt | 206,000,000 | 223,000,000 |
Other regulatory assets, deferred | 6,943,000,000 | 6,851,000,000 |
Other deferred charges and assets | 1,577,000,000 | 1,406,000,000 |
Total deferred charges and other assets | 9,551,000,000 | 10,109,000,000 |
Total Assets | 111,005,000,000 | 109,697,000,000 |
Current Liabilities: | ||
Securities due within one year | 3,892,000,000 | 2,587,000,000 |
Notes payable | 2,439,000,000 | 2,241,000,000 |
Energy marketing trade payables | 546,000,000 | 597,000,000 |
Accounts payable | 2,530,000,000 | 2,228,000,000 |
Customer deposits | 542,000,000 | 558,000,000 |
Accrued taxes — | ||
Accrued income taxes | 6,000,000 | 193,000,000 |
Unrecognized tax benefits | 18,000,000 | 385,000,000 |
Other accrued taxes | 613,000,000 | 667,000,000 |
Accrued interest | 488,000,000 | 518,000,000 |
Accrued compensation | 959,000,000 | 915,000,000 |
Asset retirement obligations, current | 351,000,000 | 378,000,000 |
Acquisitions payable | 5,000,000 | 489,000,000 |
Other regulatory liabilities, current | 337,000,000 | 236,000,000 |
Other current liabilities | 868,000,000 | 925,000,000 |
Total current liabilities | 13,594,000,000 | 12,917,000,000 |
Long-Term Debt | ||
Unamortized debt issuance expense | (226,000,000) | (213,000,000) |
Long-term Debt | 44,462,000,000 | 42,629,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 6,842,000,000 | 14,092,000,000 |
Accumulated deferred ITCs | 2,267,000,000 | 2,228,000,000 |
Employee benefit obligations | 2,256,000,000 | 2,299,000,000 |
Asset retirement obligations, deferred | 4,473,000,000 | 4,136,000,000 |
Accrued environmental remediation | 389,000,000 | 397,000,000 |
Other cost of removal obligations | 2,684,000,000 | 2,748,000,000 |
Other regulatory liabilities, deferred | 239,000,000 | 258,000,000 |
Other deferred credits and liabilities | 691,000,000 | 880,000,000 |
Total deferred credits and other liabilities | 27,097,000,000 | 27,257,000,000 |
Total Liabilities | 85,153,000,000 | 82,803,000,000 |
Redeemable preferred stock of subsidiaries | 324,000,000 | 118,000,000 |
Redeemable noncontrolling interests | 0 | 164,000,000 |
Total stockholders' equity | 25,528,000,000 | 26,612,000,000 |
Total Liabilities and Stockholder's Equity | 111,005,000,000 | 109,697,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Common stock | 5,038,000,000 | 4,952,000,000 |
Paid-in capital | 10,469,000,000 | 9,661,000,000 |
Retained earnings | 8,885,000,000 | 10,356,000,000 |
Accumulated other comprehensive loss | (189,000,000) | (180,000,000) |
Total common stockholders' equity | 24,167,000,000 | 24,758,000,000 |
Noncontrolling interests | 1,361,000,000 | 1,854,000,000 |
ALABAMA POWER CO | ||
Current Assets: | ||
Cash and cash equivalents | 544,000,000 | 420,000,000 |
Receivables — | ||
Customer accounts receivable | 355,000,000 | 348,000,000 |
Unbilled revenues | 162,000,000 | 146,000,000 |
Other accounts and notes receivable | 55,000,000 | 27,000,000 |
Affiliated | 43,000,000 | 40,000,000 |
Accumulated provision for uncollectible accounts | (9,000,000) | (10,000,000) |
Materials and supplies | 458,000,000 | 435,000,000 |
Fossil fuel for generation | 184,000,000 | 205,000,000 |
Other regulatory assets, current | 124,000,000 | 149,000,000 |
Other current assets | 90,000,000 | 45,000,000 |
Total current assets | 2,006,000,000 | 1,805,000,000 |
Property, Plant, and Equipment: | ||
In service | 27,326,000,000 | 26,031,000,000 |
Less: Accumulated depreciation | 9,563,000,000 | 9,112,000,000 |
Plant in service, net of depreciation | 17,763,000,000 | 16,919,000,000 |
Nuclear fuel, at amortized cost | 339,000,000 | 336,000,000 |
Construction work in progress | 908,000,000 | 491,000,000 |
Total property, plant, and equipment | 19,010,000,000 | 17,746,000,000 |
Other Property and Investments: | ||
Equity investments in unconsolidated subsidiaries | 67,000,000 | 66,000,000 |
Nuclear decommissioning trusts, at fair value | 903,000,000 | 792,000,000 |
Miscellaneous property and investments | 124,000,000 | 112,000,000 |
Total other property and investments | 1,094,000,000 | 970,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 239,000,000 | 525,000,000 |
Deferred under recovered regulatory clause revenues | 54,000,000 | 150,000,000 |
Other regulatory assets, deferred | 1,272,000,000 | 1,157,000,000 |
Other deferred charges and assets | 189,000,000 | 163,000,000 |
Total deferred charges and other assets | 1,754,000,000 | 1,995,000,000 |
Total Assets | 23,864,000,000 | 22,516,000,000 |
Current Liabilities: | ||
Securities due within one year | 0 | 561,000,000 |
Notes payable | 3,000,000 | 0 |
Accounts payable - Affiliated | 327,000,000 | 297,000,000 |
Accounts payable - Other | 585,000,000 | 433,000,000 |
Customer deposits | 92,000,000 | 88,000,000 |
Accrued taxes — | ||
Accrued income taxes | 9,000,000 | 45,000,000 |
Other accrued taxes | 45,000,000 | 42,000,000 |
Accrued interest | 77,000,000 | 78,000,000 |
Accrued compensation | 205,000,000 | 193,000,000 |
Other regulatory liabilities, current | 1,000,000 | 85,000,000 |
Other current liabilities | 59,000,000 | 76,000,000 |
Total current liabilities | 1,400,000,000 | 1,898,000,000 |
Long-Term Debt | ||
Unamortized debt premium (discount), net | (11,000,000) | (9,000,000) |
Unamortized debt issuance expense | (51,000,000) | (46,000,000) |
Long-term Debt | 7,628,000,000 | 6,535,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 2,760,000,000 | 4,654,000,000 |
Accumulated deferred ITCs | 112,000,000 | 110,000,000 |
Employee benefit obligations | 304,000,000 | 300,000,000 |
Asset retirement obligations, deferred | 1,702,000,000 | 1,503,000,000 |
Other cost of removal obligations | 609,000,000 | 684,000,000 |
Other regulatory liabilities, deferred | 84,000,000 | 100,000,000 |
Other deferred credits and liabilities | 63,000,000 | 63,000,000 |
Total deferred credits and other liabilities | 7,716,000,000 | 7,479,000,000 |
Total Liabilities | 16,744,000,000 | 15,912,000,000 |
Redeemable preferred stock of subsidiaries | 291,000,000 | 85,000,000 |
Redeemable preferred stock | 291,000,000 | 85,000,000 |
Total stockholders' equity | 6,829,000,000 | 6,323,000,000 |
Total Liabilities and Stockholder's Equity | 23,864,000,000 | 22,516,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Common stock | 1,222,000,000 | 1,222,000,000 |
Paid-in capital | 2,986,000,000 | 2,613,000,000 |
Retained earnings | 2,647,000,000 | 2,518,000,000 |
Accumulated other comprehensive loss | (26,000,000) | (30,000,000) |
Total common stockholders' equity | 6,829,000,000 | 6,323,000,000 |
Preference stock | 0 | 196,000,000 |
GEORGIA POWER CO | ||
Current Assets: | ||
Cash and cash equivalents | 852,000,000 | 3,000,000 |
Receivables — | ||
Customer accounts receivable | 708,000,000 | 523,000,000 |
Unbilled revenues | 255,000,000 | 224,000,000 |
Joint owner accounts receivable | 262,000,000 | 57,000,000 |
Other accounts and notes receivable | 76,000,000 | 81,000,000 |
Affiliated | 24,000,000 | 18,000,000 |
Accumulated provision for uncollectible accounts | (3,000,000) | (3,000,000) |
Materials and supplies | 504,000,000 | 479,000,000 |
Fossil fuel for generation | 314,000,000 | 298,000,000 |
Prepaid expenses | 216,000,000 | 105,000,000 |
Other regulatory assets, current | 205,000,000 | 193,000,000 |
Other current assets | 15,000,000 | 38,000,000 |
Total current assets | 3,428,000,000 | 2,016,000,000 |
Property, Plant, and Equipment: | ||
In service | 34,861,000,000 | 33,841,000,000 |
Less: Accumulated depreciation | 11,704,000,000 | 11,317,000,000 |
Plant in service, net of depreciation | 23,157,000,000 | 22,524,000,000 |
Nuclear fuel, at amortized cost | 544,000,000 | 569,000,000 |
Construction work in progress | 4,613,000,000 | 4,939,000,000 |
Total property, plant, and equipment | 28,314,000,000 | 28,032,000,000 |
Other Property and Investments: | ||
Equity investments in unconsolidated subsidiaries | 53,000,000 | 60,000,000 |
Nuclear decommissioning trusts, at fair value | 929,000,000 | 814,000,000 |
Miscellaneous property and investments | 59,000,000 | 46,000,000 |
Total other property and investments | 1,041,000,000 | 920,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 516,000,000 | 676,000,000 |
Other regulatory assets, deferred | 2,932,000,000 | 2,774,000,000 |
Other deferred charges and assets | 548,000,000 | 417,000,000 |
Total deferred charges and other assets | 3,996,000,000 | 3,867,000,000 |
Total Assets | 36,779,000,000 | 34,835,000,000 |
Current Liabilities: | ||
Securities due within one year | 857,000,000 | 460,000,000 |
Notes payable | 150,000,000 | 391,000,000 |
Accounts payable - Affiliated | 493,000,000 | 438,000,000 |
Accounts payable - Other | 834,000,000 | 589,000,000 |
Customer deposits | 270,000,000 | 265,000,000 |
Accrued taxes — | ||
Accrued income taxes | 0 | 17,000,000 |
Other accrued taxes | 344,000,000 | 390,000,000 |
Accrued interest | 123,000,000 | 106,000,000 |
Accrued compensation | 219,000,000 | 224,000,000 |
Asset retirement obligations, current | 270,000,000 | 299,000,000 |
Other regulatory liabilities, current | 191,000,000 | 31,000,000 |
Over recovered regulatory clause revenues, current | 0 | 84,000,000 |
Other current liabilities | 198,000,000 | 182,000,000 |
Total current liabilities | 3,949,000,000 | 3,476,000,000 |
Long-Term Debt | ||
Unamortized debt premium (discount), net | (12,000,000) | (10,000,000) |
Unamortized debt issuance expense | (124,000,000) | (117,000,000) |
Long-term Debt | 11,073,000,000 | 10,225,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 3,175,000,000 | 6,000,000,000 |
Accumulated deferred ITCs | 248,000,000 | 256,000,000 |
Employee benefit obligations | 659,000,000 | 703,000,000 |
Deferred capacity expense | 199,000,000 | 217,000,000 |
Asset retirement obligations, deferred | 2,368,000,000 | 2,233,000,000 |
Other deferred credits and liabilities | 128,000,000 | 199,000,000 |
Total deferred credits and other liabilities | 9,826,000,000 | 9,512,000,000 |
Total Liabilities | 24,848,000,000 | 23,213,000,000 |
Redeemable preferred stock | 0 | 45,000,000 |
Total stockholders' equity | 11,931,000,000 | 11,356,000,000 |
Total Liabilities and Stockholder's Equity | 36,779,000,000 | 34,835,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Common stock | 398,000,000 | 398,000,000 |
Paid-in capital | 7,328,000,000 | 6,885,000,000 |
Retained earnings | 4,215,000,000 | 4,086,000,000 |
Accumulated other comprehensive loss | (10,000,000) | (13,000,000) |
Total common stockholders' equity | 11,931,000,000 | 11,356,000,000 |
Preference stock | 0 | 221,000,000 |
GULF POWER CO | ||
Current Assets: | ||
Cash and cash equivalents | 28,000,000 | 56,000,000 |
Receivables — | ||
Customer accounts receivable | 76,000,000 | 72,000,000 |
Unbilled revenues | 67,000,000 | 55,000,000 |
Under recovered fuel clause revenues | 27,000,000 | 17,000,000 |
Other accounts and notes receivable | 7,000,000 | 6,000,000 |
Affiliated | 14,000,000 | 17,000,000 |
Accumulated provision for uncollectible accounts | (1,000,000) | (1,000,000) |
Materials and supplies | 57,000,000 | 55,000,000 |
Fossil fuel for generation | 63,000,000 | 71,000,000 |
Other regulatory assets, current | 56,000,000 | 44,000,000 |
Other current assets | 21,000,000 | 30,000,000 |
Total current assets | 415,000,000 | 422,000,000 |
Property, Plant, and Equipment: | ||
In service | 5,196,000,000 | 5,140,000,000 |
Less: Accumulated depreciation | 1,461,000,000 | 1,382,000,000 |
Plant in service, net of depreciation | 3,735,000,000 | 3,758,000,000 |
Construction work in progress | 91,000,000 | 51,000,000 |
Total property, plant, and equipment | 3,826,000,000 | 3,809,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 31,000,000 | 58,000,000 |
Other regulatory assets, deferred | 502,000,000 | 512,000,000 |
Other deferred charges and assets | 23,000,000 | 21,000,000 |
Total deferred charges and other assets | 556,000,000 | 591,000,000 |
Total Assets | 4,797,000,000 | 4,822,000,000 |
Current Liabilities: | ||
Securities due within one year | 0 | 87,000,000 |
Notes payable | 45,000,000 | 268,000,000 |
Accounts payable - Affiliated | 52,000,000 | 59,000,000 |
Accounts payable - Other | 75,000,000 | 54,000,000 |
Customer deposits | 35,000,000 | 35,000,000 |
Accrued taxes — | ||
Accrued income taxes | 1,000,000 | 1,000,000 |
Other accrued taxes | 9,000,000 | 19,000,000 |
Accrued interest | 9,000,000 | 8,000,000 |
Accrued compensation | 39,000,000 | 40,000,000 |
Asset retirement obligations, current | 37,000,000 | 16,000,000 |
Deferred capacity expense, current | 22,000,000 | 22,000,000 |
Other regulatory liabilities, current | 0 | 16,000,000 |
Other current liabilities | 27,000,000 | 24,000,000 |
Total current liabilities | 351,000,000 | 649,000,000 |
Long-Term Debt | ||
Unamortized debt premium (discount), net | (5,000,000) | (5,000,000) |
Unamortized debt issuance expense | (9,000,000) | (7,000,000) |
Long-term Debt | 1,285,000,000 | 987,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 537,000,000 | 948,000,000 |
Employee benefit obligations | 102,000,000 | 96,000,000 |
Deferred capacity expense | 97,000,000 | 119,000,000 |
Asset retirement obligations, deferred | 105,000,000 | 120,000,000 |
Other cost of removal obligations | 221,000,000 | 249,000,000 |
Other regulatory liabilities, deferred | 43,000,000 | 45,000,000 |
Other deferred credits and liabilities | 67,000,000 | 71,000,000 |
Total deferred credits and other liabilities | 1,630,000,000 | 1,650,000,000 |
Total Liabilities | 3,266,000,000 | 3,286,000,000 |
Total stockholders' equity | 1,531,000,000 | 1,389,000,000 |
Total Liabilities and Stockholder's Equity | 4,797,000,000 | 4,822,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Common stock | 678,000,000 | 503,000,000 |
Paid-in capital | 594,000,000 | 589,000,000 |
Retained earnings | 259,000,000 | 296,000,000 |
Accumulated other comprehensive loss | 0 | 1,000,000 |
Total common stockholders' equity | 1,531,000,000 | 1,389,000,000 |
Preference stock | 0 | 147,000,000 |
MISSISSIPPI POWER CO | ||
Current Assets: | ||
Cash and cash equivalents | 248,000,000 | 224,000,000 |
Receivables — | ||
Customer accounts receivable | 36,000,000 | 29,000,000 |
Unbilled revenues | 41,000,000 | 42,000,000 |
Income taxes receivable, current | 4,000,000 | 544,000,000 |
Other accounts and notes receivable | 12,000,000 | 14,000,000 |
Affiliated | 16,000,000 | 15,000,000 |
Materials and supplies | 44,000,000 | 76,000,000 |
Fossil fuel for generation | 17,000,000 | 100,000,000 |
Other regulatory assets, current | 125,000,000 | 115,000,000 |
Other current assets | 9,000,000 | 8,000,000 |
Total current assets | 552,000,000 | 1,167,000,000 |
Property, Plant, and Equipment: | ||
In service | 4,773,000,000 | 4,865,000,000 |
Less: Accumulated depreciation | 1,325,000,000 | 1,289,000,000 |
Plant in service, net of depreciation | 3,448,000,000 | 3,576,000,000 |
Construction work in progress | 84,000,000 | 2,545,000,000 |
Total property, plant, and equipment | 3,532,000,000 | 6,121,000,000 |
Other Property and Investments: | ||
Total other property and investments | 30,000,000 | 12,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 35,000,000 | 361,000,000 |
Other regulatory assets, deferred | 437,000,000 | 518,000,000 |
Accumulated deferred income taxes | 247,000,000 | 0 |
Other deferred charges and assets | 33,000,000 | 56,000,000 |
Total deferred charges and other assets | 752,000,000 | 935,000,000 |
Total Assets | 4,866,000,000 | 8,235,000,000 |
Current Liabilities: | ||
Securities due within one year, parent | 0 | 551,000,000 |
Securities due within one year | 989,000,000 | 629,000,000 |
Notes payable | 4,000,000 | 23,000,000 |
Accounts payable - Affiliated | 59,000,000 | 62,000,000 |
Accounts payable - Other | 96,000,000 | 135,000,000 |
Accrued taxes — | ||
Accrued income taxes | 40,000,000 | 0 |
Unrecognized tax benefits | 0 | 383,000,000 |
Other accrued taxes | 101,000,000 | 99,000,000 |
Accrued interest | 16,000,000 | 46,000,000 |
Accrued compensation | 39,000,000 | 42,000,000 |
Asset retirement obligations, current | 37,000,000 | 32,000,000 |
Over recovered regulatory clause liabilities | 0 | 51,000,000 |
Other current liabilities | 82,000,000 | 36,000,000 |
Total current liabilities | 1,463,000,000 | 1,538,000,000 |
Long-Term Debt | ||
Long-term debt affiliated | 0 | 551,000,000 |
Unamortized debt issuance expense | (7,000,000) | (8,000,000) |
Long-term Debt | 1,097,000,000 | 2,424,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 0 | 756,000,000 |
Employee benefit obligations | 116,000,000 | 115,000,000 |
Asset retirement obligations, deferred | 137,000,000 | 146,000,000 |
Other cost of removal obligations | 178,000,000 | 170,000,000 |
Other regulatory liabilities, deferred | 79,000,000 | 77,000,000 |
Other deferred credits and liabilities | 33,000,000 | 26,000,000 |
Total deferred credits and other liabilities | 915,000,000 | 1,297,000,000 |
Total Liabilities | 3,475,000,000 | 5,259,000,000 |
Redeemable preferred stock | 33,000,000 | 33,000,000 |
Total stockholders' equity | 1,358,000,000 | 2,943,000,000 |
Total Liabilities and Stockholder's Equity | 4,866,000,000 | 8,235,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Common stock | 38,000,000 | 38,000,000 |
Paid-in capital | 4,529,000,000 | 3,525,000,000 |
Retained earnings | (3,205,000,000) | (616,000,000) |
Accumulated other comprehensive loss | (4,000,000) | (4,000,000) |
Total common stockholders' equity | 1,358,000,000 | 2,943,000,000 |
SOUTHERN POWER CO | ||
Current Assets: | ||
Cash and cash equivalents | 129,000,000 | 1,099,000,000 |
Receivables — | ||
Customer accounts receivable | 117,000,000 | 102,000,000 |
Other accounts and notes receivable | 98,000,000 | 34,000,000 |
Affiliated | 50,000,000 | 57,000,000 |
Materials and supplies | 278,000,000 | 337,000,000 |
Prepaid income taxes | 50,000,000 | 74,000,000 |
Other current assets | 36,000,000 | 54,000,000 |
Total current assets | 758,000,000 | 1,757,000,000 |
Property, Plant, and Equipment: | ||
In service | 13,755,000,000 | 12,728,000,000 |
Less: Accumulated depreciation | 1,910,000,000 | 1,484,000,000 |
Plant in service, net of depreciation | 11,845,000,000 | 11,244,000,000 |
Construction work in progress | 511,000,000 | 398,000,000 |
Total property, plant, and equipment | 12,356,000,000 | 11,642,000,000 |
Other Property and Investments: | ||
Intangible assets, net of amortization | 411,000,000 | 436,000,000 |
Total other property and investments | 411,000,000 | 436,000,000 |
Deferred Charges and Other Assets: | ||
Prepaid long-term service agreements | 118,000,000 | 101,000,000 |
Accumulated deferred income taxes | 925,000,000 | 594,000,000 |
Income taxes receivable, non-current | 72,000,000 | 11,000,000 |
Other deferred charges and assets | 566,000,000 | 628,000,000 |
Total deferred charges and other assets | 1,681,000,000 | 1,334,000,000 |
Total Assets | 15,206,000,000 | 15,169,000,000 |
Current Liabilities: | ||
Securities due within one year | 770,000,000 | 560,000,000 |
Notes payable | 105,000,000 | 209,000,000 |
Accounts payable - Affiliated | 102,000,000 | 88,000,000 |
Accounts payable - Other | 103,000,000 | 278,000,000 |
Accrued taxes — | ||
Accrued income taxes | 0 | 148,000,000 |
Other accrued taxes | 4,000,000 | 7,000,000 |
Acquisitions payable | 5,000,000 | 461,000,000 |
Other current liabilities | 143,000,000 | 152,000,000 |
Total current liabilities | 1,232,000,000 | 1,903,000,000 |
Long-Term Debt | ||
Unamortized debt premium (discount), net | (10,000,000) | (12,000,000) |
Unamortized debt issuance expense | (28,000,000) | (29,000,000) |
Long-term Debt | 5,071,000,000 | 5,068,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 199,000,000 | 152,000,000 |
Accumulated deferred investment tax credits | 1,884,000,000 | 1,839,000,000 |
Other deferred credits and liabilities | 322,000,000 | 368,000,000 |
Total deferred credits and other liabilities | 2,405,000,000 | 2,359,000,000 |
Total Liabilities | 8,708,000,000 | 9,330,000,000 |
Redeemable noncontrolling interest | 0 | 164,000,000 |
Redeemable noncontrolling interests | 0 | |
Total stockholders' equity | 6,498,000,000 | 5,675,000,000 |
Total Liabilities and Stockholder's Equity | 15,206,000,000 | 15,169,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Common stock | 0 | 0 |
Paid-in capital | 3,662,000,000 | 3,671,000,000 |
Retained earnings | 1,478,000,000 | 724,000,000 |
Accumulated other comprehensive loss | (2,000,000) | 35,000,000 |
Total common stockholders' equity | 5,138,000,000 | 4,430,000,000 |
Noncontrolling interests | 1,360,000,000 | 1,245,000,000 |
SOUTHERN POWER CO | 1.50% due 2018 | ||
Long-Term Debt | ||
Senior notes | 0 | 350,000,000 |
SOUTHERN POWER CO | 1.95% due 2019 | ||
Long-Term Debt | ||
Senior notes | 600,000,000 | 600,000,000 |
SOUTHERN POWER CO | 2.375% due 2020 | ||
Long-Term Debt | ||
Senior notes | 300,000,000 | 300,000,000 |
SOUTHERN POWER CO | 2.50% due 2021 | ||
Long-Term Debt | ||
Senior notes | 300,000,000 | 300,000,000 |
SOUTHERN POWER CO | 1.00% due 2022 | ||
Long-Term Debt | ||
Senior notes | 720,000,000 | 632,000,000 |
SOUTHERN POWER CO | 1.85% to 5.25% due 2023-2046 | ||
Long-Term Debt | ||
Senior notes | 2,664,000,000 | 2,592,000,000 |
SOUTHERN POWER CO | Variable rate (1.88% at 12/31/17) due 2018 | ||
Long-Term Debt | ||
Other long-term debt | 0 | 320,000,000 |
SOUTHERN POWER CO | Variable rate (2.18% at 12/31/17) due 2020 | ||
Long-Term Debt | ||
Other long-term debt | 525,000,000 | 0 |
SOUTHERN POWER CO | Variable rate (3.75% at 1/1/17) due 2032-2036 | ||
Long-Term Debt | ||
Other long-term debt | 0 | 15,000,000 |
SOUTHERN Co GAS | ||
Current Assets: | ||
Cash and cash equivalents | 73,000,000 | 19,000,000 |
Receivables — | ||
Customer accounts receivable | 400,000,000 | 364,000,000 |
Energy marketing receivable | 607,000,000 | 623,000,000 |
Unbilled revenues | 285,000,000 | 239,000,000 |
Other accounts and notes receivable | 103,000,000 | 76,000,000 |
Accumulated provision for uncollectible accounts | (28,000,000) | (27,000,000) |
Materials and supplies | 24,000,000 | 26,000,000 |
Natural gas for sale | 595,000,000 | 631,000,000 |
Prepaid expenses | 53,000,000 | 55,000,000 |
Other regulatory assets, current | 94,000,000 | 81,000,000 |
Prepaid income taxes | 26,000,000 | 24,000,000 |
Assets from risk management activities, net of collateral | 135,000,000 | 128,000,000 |
Other current assets | 28,000,000 | 11,000,000 |
Total current assets | 2,395,000,000 | 2,250,000,000 |
Property, Plant, and Equipment: | ||
In service | 15,833,000,000 | 14,508,000,000 |
Less: Accumulated depreciation | 4,596,000,000 | 4,439,000,000 |
Plant in service, net of depreciation | 11,237,000,000 | 10,069,000,000 |
Construction work in progress | 491,000,000 | 496,000,000 |
Total property, plant, and equipment | 11,728,000,000 | 10,565,000,000 |
Other Property and Investments: | ||
Goodwill | 5,967,000,000 | 5,967,000,000 |
Equity investments in unconsolidated subsidiaries | 1,477,000,000 | 1,541,000,000 |
Other intangible assets, net of amortization | 280,000,000 | 366,000,000 |
Miscellaneous property and investments | 21,000,000 | 21,000,000 |
Total other property and investments | 7,745,000,000 | 7,895,000,000 |
Deferred Charges and Other Assets: | ||
Other regulatory assets, deferred | 901,000,000 | 973,000,000 |
Other deferred charges and assets | 218,000,000 | 170,000,000 |
Total deferred charges and other assets | 1,119,000,000 | 1,143,000,000 |
Total Assets | 22,987,000,000 | 21,853,000,000 |
Current Liabilities: | ||
Securities due within one year | 157,000,000 | 22,000,000 |
Notes payable | 1,518,000,000 | 1,257,000,000 |
Energy marketing trade payables | 546,000,000 | 597,000,000 |
Accounts payable | 446,000,000 | 348,000,000 |
Customer deposits | 128,000,000 | 153,000,000 |
Accrued taxes — | ||
Accrued income taxes | 40,000,000 | 26,000,000 |
Other accrued taxes | 78,000,000 | 68,000,000 |
Accrued interest | 51,000,000 | 48,000,000 |
Accrued compensation | 74,000,000 | 58,000,000 |
Other regulatory liabilities, current | 135,000,000 | 102,000,000 |
Accrued environmental remediation, current | 46,000,000 | 69,000,000 |
Liabilities from risk management activities | 69,000,000 | 62,000,000 |
Other current liabilities | 113,000,000 | 108,000,000 |
Total current liabilities | 3,401,000,000 | 2,918,000,000 |
Long-Term Debt | ||
Unamortized debt premium (discount), net | (17,000,000) | (9,000,000) |
Long-term Debt | 5,891,000,000 | 5,259,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 1,089,000,000 | 1,975,000,000 |
Employee benefit obligations | 415,000,000 | 441,000,000 |
Accrued environmental remediation | 342,000,000 | 357,000,000 |
Other cost of removal obligations | 1,646,000,000 | 1,616,000,000 |
Other regulatory liabilities, deferred | 30,000,000 | 29,000,000 |
Other deferred credits and liabilities | 88,000,000 | 127,000,000 |
Total deferred credits and other liabilities | 4,673,000,000 | 4,567,000,000 |
Total Liabilities | 13,965,000,000 | 12,744,000,000 |
Redeemable noncontrolling interests | 0 | |
Total stockholders' equity | 9,022,000,000 | 9,109,000,000 |
Total Liabilities and Stockholder's Equity | 22,987,000,000 | 21,853,000,000 |
Commitments and Contingent Matters | ||
Common Stockholders' Equity: | ||
Paid-in capital | 9,214,000,000 | 9,095,000,000 |
Retained earnings | (212,000,000) | (12,000,000) |
Accumulated other comprehensive loss | 20,000,000 | 26,000,000 |
Total common stockholders' equity | 9,022,000,000 | 9,109,000,000 |
Long-Term Debt, Other | MISSISSIPPI POWER CO | ||
Current Liabilities: | ||
Securities due within one year | $ 989,000,000 | $ 78,000,000 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Amortization expense on other intangible assets | $ 186 | $ 62 |
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 CO | ||
Amortization expense on other intangible assets | $ 47 | $ 22 |
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 CO | 1.50% due 2018 | ||
Fixed stated interest rate of debt obligation | 1.50% | |
SOUTHERN POWER CO | 1.95% due 2019 | ||
Fixed stated interest rate of debt obligation | 1.95% | 1.95% |
SOUTHERN POWER CO | 2.375% due 2020 | ||
Fixed stated interest rate of debt obligation | 2.375% | 2.375% |
SOUTHERN POWER CO | 2.50% due 2021 | ||
Fixed stated interest rate of debt obligation | 2.50% | 2.50% |
SOUTHERN POWER CO | 1.00% due 2022 | ||
Fixed stated interest rate of debt obligation | 1.00% | |
SOUTHERN POWER CO | Variable rate (1.88% at 12/31/17) due 2018 | ||
Fixed stated interest rate of debt obligation | 1.88% | 1.88% |
SOUTHERN POWER CO | Variable rate (2.18% at 12/31/17) due 2020 | ||
Fixed stated interest rate of debt obligation | 2.18% | |
SOUTHERN POWER CO | Variable rate (3.75% at 1/1/17) due 2032-2036 | ||
Fixed stated interest rate of debt obligation | 3.75% | 3.75% |
SOUTHERN Co GAS | ||
Amortization expense on other intangible assets | $ 120 | $ 34 |
Common stock, par value per share (in dollars per share) | $ 0.01 | $ 10,000 |
Common stock, shares authorized | 100,000,000 | 100 |
Common stock, shares outstanding | 100 | 100 |
Minimum | SOUTHERN POWER CO | Senior Notes Due Two Thousand Twenty Three Through Two Thousand Forty Six [Member] | ||
Fixed stated interest rate of debt obligation | 1.85% | |
Minimum | SOUTHERN POWER CO | 1.85% to 5.25% due 2023-2046 | ||
Fixed stated interest rate of debt obligation | 1.85% | |
Maximum | SOUTHERN POWER CO | 1.85% to 5.25% due 2023-2046 | ||
Fixed stated interest rate of debt obligation | 5.25% | 5.25% |
Predecessor | SOUTHERN Co GAS | ||
Amortization expense on other intangible assets | $ 34 |
Consolidated Statements of Capi
Consolidated Statements of Capitalization - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Maturity | ||
Long-term debt payable to affiliated trusts | $ 206,000,000 | $ 206,000,000 |
2,017 | 0 | 2,019,000,000 |
2,018 | 2,402,000,000 | 2,403,000,000 |
2,019 | 3,074,000,000 | 3,076,000,000 |
2,020 | 2,273,000,000 | 1,326,000,000 |
2,021 | 2,643,000,000 | 2,655,000,000 |
2,022 | 2,016,000,000 | 1,378,000,000 |
After Five Years | 22,142,000,000 | 20,369,000,000 |
Total long-term senior notes and debt | 36,820,000,000 | 35,247,000,000 |
Pollution control revenue bonds — | ||
Total other long-term debt | 10,987,000,000 | 9,404,000,000 |
Unamortized fair value adjustment of long-term debt | 525,000,000 | 578,000,000 |
Capitalized lease obligations | 204,000,000 | 136,000,000 |
Unamortized debt premium | 44,000,000 | 52,000,000 |
Unamortized debt discount | (206,000,000) | (194,000,000) |
Unamortized debt issuance expense | (226,000,000) | (213,000,000) |
Total long-term debt (annual interest requirement — $1.8 billion) | 48,354,000,000 | 45,216,000,000 |
Less amount due within one year | 3,892,000,000 | 2,587,000,000 |
Long-term debt excluding amount due within one year | $ 44,462,000,000 | $ 42,629,000,000 |
Percent capitalization | 63.20% | 61.30% |
Cumulative preferred stock | ||
Redeemable preferred stock | $ 324,000,000 | $ 118,000,000 |
Total redeemable preferred stock - percent capitalization | 0.50% | 0.20% |
Redeemable noncontrolling interests | $ 0 | $ 164,000,000 |
Redeemable Noncontrolling Interest As Percent Of Capitalization | 0.00% | 0.20% |
Common Stockholders' Equity: | ||
Common stock | $ 5,038,000,000 | $ 4,952,000,000 |
Paid-in capital | 10,469,000,000 | 9,661,000,000 |
Treasury, at cost | (36,000,000) | (31,000,000) |
Retained earnings | 8,885,000,000 | 10,356,000,000 |
Accumulated other comprehensive loss | (189,000,000) | (180,000,000) |
Total common stockholders' equity | $ 24,167,000,000 | $ 24,758,000,000 |
Total common stockholders' equity - percent capitalization | 34.40% | 35.60% |
Preferred and preference stock of subsidiaries | $ 1,361,000,000 | $ 1,854,000,000 |
Total preferred and preference stock of subsidiaries - percent capitalization | 1.90% | 2.70% |
Total stockholders' equity | $ 25,528,000,000 | $ 26,612,000,000 |
Total capitalization | $ 70,314,000,000 | $ 69,523,000,000 |
Percent capitalization | 100.00% | 100.00% |
Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock | ||
Cumulative preferred stock | ||
Redeemable preferred stock | $ 324,000,000 | $ 81,000,000 |
Redeemable Preferred Stock, $1 par value | Cumulative Preferred Stock | ||
Cumulative preferred stock | ||
Redeemable preferred stock | 0 | 37,000,000 |
Noncumulative Preferred Stock | ||
Common Stockholders' Equity: | ||
Preferred and preference stock of subsidiaries | 0 | 45,000,000 |
Preference Stock, $1 par value | ||
Common Stockholders' Equity: | ||
Preferred and preference stock of subsidiaries | 0 | 196,000,000 |
Preference Stock , $100 par or stated value | ||
Common Stockholders' Equity: | ||
Preferred and preference stock of subsidiaries | 0 | 368,000,000 |
Redeemable Preferred Stock | ||
Cumulative preferred stock | ||
Redeemable preferred stock | 324,000,000 | 118,000,000 |
Noncontrolling Interests | ||
Common Stockholders' Equity: | ||
Preferred and preference stock of subsidiaries | 1,361,000,000 | 1,245,000,000 |
Adjustable Rate Loans | ||
Maturity | ||
2,017 | 0 | 461,000,000 |
2,018 | 1,420,000,000 | 1,520,000,000 |
2,020 | 825,000,000 | 0 |
2,021 | 25,000,000 | 25,000,000 |
After Five Years | 0 | 15,000,000 |
Pollution control revenue bonds due 2019 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 25,000,000 | 25,000,000 |
Maturity of Pollution Control Bonds Due 2022 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 90,000,000 | 90,000,000 |
Pollution control revenue bonds due 2023 through 2049 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 1,379,000,000 | 1,339,000,000 |
Maturity of Pollution Control Bonds Period Two | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 1,680,000,000 | 1,721,000,000 |
Pollution control revenue bonds variable rate, Due 2018 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 40,000,000 | 76,000,000 |
Pollution control revenue bonds variable rate due 2021 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 65,000,000 | 65,000,000 |
Pollution control revenue bonds variable rate due 2022 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 17,000,000 | 17,000,000 |
Plant Daniel revenue bonds (7.13%) due 2021 | ||
Pollution control revenue bonds — | ||
Plant Daniel revenue bonds (7.13%) due 2021 | 270,000,000 | 270,000,000 |
Maturity Of FFB Loans Due 2020 | ||
Pollution control revenue bonds — | ||
FFB loans | 44,000,000 | 44,000,000 |
Maturity Of FFB Loans Due 2021 | ||
Pollution control revenue bonds — | ||
FFB loans | 44,000,000 | 44,000,000 |
Maturity Of Loans Due 2022 | ||
Pollution control revenue bonds — | ||
FFB loans | 44,000,000 | 44,000,000 |
Maturity Of FFB Bank Loans Due 2023 to 2053 | ||
Pollution control revenue bonds — | ||
FFB loans | 2,493,000,000 | 2,493,000,000 |
Maturity Of First Mortgage Bonds Due 2019 | ||
Pollution control revenue bonds — | ||
First mortgage bonds | 50,000,000 | 50,000,000 |
First Mortgage Bonds Due 2023 to 2057 | ||
Pollution control revenue bonds — | ||
First mortgage bonds | 975,000,000 | 575,000,000 |
Maturity Of Gas Facility Revenue Bonds Due 2022 | ||
Pollution control revenue bonds — | ||
Gas facility revenue bonds | 47,000,000 | 47,000,000 |
Maturity Of Gas Facility Revenue Bonds Due 2024 to 2033 | ||
Pollution control revenue bonds — | ||
Gas facility revenue bonds | 154,000,000 | 154,000,000 |
ALABAMA POWER CO | ||
Maturity | ||
Long-term debt payable to affiliated trusts | 206,000,000 | 206,000,000 |
2,017 | 0 | 525,000,000 |
2,019 | 200,000,000 | 200,000,000 |
2,020 | 250,000,000 | 250,000,000 |
2,021 | 220,000,000 | 220,000,000 |
2,022 | 750,000,000 | 200,000,000 |
After Five Years | 4,975,000,000 | 4,425,000,000 |
Total long-term notes payable | 6,420,000,000 | 5,845,000,000 |
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 1,060,000,000 | 1,100,000,000 |
Total other long-term debt | 1,060,000,000 | 1,096,000,000 |
Capitalized lease obligations | 4,000,000 | 4,000,000 |
Unamortized debt (discount), net | (11,000,000) | (9,000,000) |
Unamortized debt issuance expense | (51,000,000) | (46,000,000) |
Total long-term debt (annual interest requirement — $1.8 billion) | 7,628,000,000 | 7,096,000,000 |
Less amount due within one year | 0 | 561,000,000 |
Long-term debt excluding amount due within one year | $ 7,628,000,000 | $ 6,535,000,000 |
Percent capitalization | 51.70% | 49.70% |
Cumulative preferred stock | ||
Redeemable preferred stock | $ 291,000,000 | $ 85,000,000 |
Total redeemable preferred stock - percent capitalization | 2.00% | 0.70% |
Preferred stock | $ 291,000,000 | $ 85,000,000 |
Preference stock | 0 | 196,000,000 |
Common Stockholders' Equity: | ||
Common stock | 1,222,000,000 | 1,222,000,000 |
Paid-in capital | 2,986,000,000 | 2,613,000,000 |
Retained earnings | 2,647,000,000 | 2,518,000,000 |
Accumulated other comprehensive loss | (26,000,000) | (30,000,000) |
Total common stockholders' equity | $ 6,829,000,000 | $ 6,323,000,000 |
Total common stockholders' equity - percent capitalization | 46.30% | 48.10% |
Total preferred and preference stock of subsidiaries - percent capitalization | 0.00% | 1.50% |
Total stockholders' equity | $ 6,829,000,000 | $ 6,323,000,000 |
Total capitalization | $ 14,748,000,000 | $ 13,139,000,000 |
Percent capitalization | 100.00% | 100.00% |
ALABAMA POWER CO | Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock | ||
Cumulative preferred stock | ||
Redeemable preferred stock | $ 48,000,000 | $ 48,000,000 |
ALABAMA POWER CO | Redeemable Preferred Stock, $1 par value | Cumulative Preferred Stock | ||
Cumulative preferred stock | ||
Redeemable preferred stock | 243,000,000 | 37,000,000 |
ALABAMA POWER CO | Adjustable Rate Loans | ||
Maturity | ||
2,022 | 25,000,000 | 25,000,000 |
ALABAMA POWER CO | Pollution control revenue bonds variable rate, Due 2018 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 0 | 36,000,000 |
ALABAMA POWER CO | Pollution control revenue bonds variable rate due 2021 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 65,000,000 | 65,000,000 |
ALABAMA POWER CO | Pollution control revenue bonds due 2034 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 207,000,000 | 207,000,000 |
ALABAMA POWER CO | Pollution Control Revenue Bonds Variable Rate Due 2024 - 2038 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 788,000,000 | 788,000,000 |
GEORGIA POWER CO | ||
Maturity | ||
2,017 | 0 | 450,000,000 |
2,018 | 747,000,000 | 748,000,000 |
2,019 | 499,000,000 | 500,000,000 |
2,020 | 950,000,000 | 0 |
2,021 | 325,000,000 | 325,000,000 |
2,022 | 400,000,000 | 400,000,000 |
After Five Years | 4,175,000,000 | 3,775,000,000 |
Total long-term notes payable | 7,196,000,000 | 6,198,000,000 |
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 1,800,000,000 | 1,800,000,000 |
Total other long-term debt | 4,716,000,000 | 4,445,000,000 |
Capitalized lease obligations | 154,000,000 | 169,000,000 |
Unamortized debt (discount), net | (12,000,000) | (10,000,000) |
Unamortized debt issuance expense | (124,000,000) | (117,000,000) |
Total long-term debt (annual interest requirement — $1.8 billion) | 11,930,000,000 | 10,685,000,000 |
Less amount due within one year | 857,000,000 | 460,000,000 |
Long-term debt excluding amount due within one year | $ 11,073,000,000 | $ 10,225,000,000 |
Percent capitalization | 48.10% | 46.80% |
Cumulative preferred stock | ||
Preferred stock | $ 0 | $ 45,000,000 |
Preference stock | 0 | 221,000,000 |
Common Stockholders' Equity: | ||
Common stock | 398,000,000 | 398,000,000 |
Paid-in capital | 7,328,000,000 | 6,885,000,000 |
Retained earnings | 4,215,000,000 | 4,086,000,000 |
Accumulated other comprehensive loss | (10,000,000) | (13,000,000) |
Total common stockholders' equity | $ 11,931,000,000 | $ 11,356,000,000 |
Total common stockholders' equity - percent capitalization | 51.90% | 52.00% |
Total preferred and preference stock of subsidiaries - percent capitalization | 0.00% | 1.20% |
Total stockholders' equity | $ 11,931,000,000 | $ 11,356,000,000 |
Total capitalization | $ 23,004,000,000 | $ 21,847,000,000 |
Percent capitalization | 100.00% | 100.00% |
GEORGIA POWER CO | Noncumulative Preferred Stock | ||
Cumulative preferred stock | ||
Total preferred and preference stock | $ 0 | $ 266,000,000 |
GEORGIA POWER CO | Noncumulative Preferred Stock, $25 par value | ||
Cumulative preferred stock | ||
Preferred stock | 0 | 45,000,000 |
GEORGIA POWER CO | Noncumulative Preferred Stock, $100 par value | ||
Cumulative preferred stock | ||
Preference stock | 0 | 221,000,000 |
GEORGIA POWER CO | Adjustable Rate Loans | ||
Maturity | ||
2,018 | 100,000,000 | 0 |
GEORGIA POWER CO | Pollution control revenue bonds due 2023 through 2049 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 53,000,000 | 53,000,000 |
GEORGIA POWER CO | Maturity of Pollution Control Bonds Period Two | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 940,000,000 | 900,000,000 |
GEORGIA POWER CO | Maturity Of Pollution Control Bonds Variable Rate Due 2018 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 13,000,000 | 13,000,000 |
GEORGIA POWER CO | Maturity of Pollution Control Bonds Two Thousand Twenty Six to Two Thousand Fifty Three | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 815,000,000 | 854,000,000 |
GEORGIA POWER CO | Maturity Of FFB Loans Due 2020 | ||
Pollution control revenue bonds — | ||
FFB loans | 44,000,000 | 44,000,000 |
GEORGIA POWER CO | Maturity Of FFB Loans Due 2021 | ||
Pollution control revenue bonds — | ||
FFB loans | 44,000,000 | 44,000,000 |
GEORGIA POWER CO | Maturity Of Loans Due Two Thousand Twenty Two | ||
Pollution control revenue bonds — | ||
FFB loans | 44,000,000 | 44,000,000 |
GEORGIA POWER CO | Maturity Of FFB Bank Loans Due 2023 to 2053 | ||
Pollution control revenue bonds — | ||
FFB loans | 2,493,000,000 | 2,493,000,000 |
GEORGIA POWER CO | Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077 | ||
Pollution control revenue bonds — | ||
Junior subordinated notes | 270,000,000 | 0 |
GULF POWER CO | ||
Maturity | ||
2,018 | 0 | |
2,019 | 0 | |
2,020 | 175,000,000 | 175,000,000 |
2,021 | 0 | |
2,022 | 141,000,000 | |
Total long-term notes payable | 990,000,000 | 777,000,000 |
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 309,000,000 | 309,000,000 |
Total other long-term debt | 309,000,000 | 309,000,000 |
Unamortized debt (discount), net | (5,000,000) | (5,000,000) |
Unamortized debt issuance expense | (9,000,000) | (7,000,000) |
Total long-term debt (annual interest requirement — $1.8 billion) | 1,285,000,000 | 1,074,000,000 |
Less amount due within one year | 0 | 87,000,000 |
Long-term debt excluding amount due within one year | $ 1,285,000,000 | $ 987,000,000 |
Percent capitalization | 45.60% | 39.10% |
Cumulative preferred stock | ||
Total redeemable preferred stock - percent capitalization | 0.00% | 5.80% |
Preference stock | $ 0 | $ 147,000,000 |
Common Stockholders' Equity: | ||
Common stock | 678,000,000 | 503,000,000 |
Paid-in capital | 594,000,000 | 589,000,000 |
Retained earnings | 259,000,000 | 296,000,000 |
Accumulated other comprehensive loss | 0 | 1,000,000 |
Total common stockholders' equity | $ 1,531,000,000 | $ 1,389,000,000 |
Total common stockholders' equity - percent capitalization | 54.40% | 55.10% |
Total stockholders' equity | $ 1,531,000,000 | $ 1,389,000,000 |
Total capitalization | $ 2,816,000,000 | $ 2,523,000,000 |
Percent capitalization | 100.00% | 100.00% |
GULF POWER CO | 6% Preference stock | ||
Cumulative preferred stock | ||
Preference stock | $ 0 | $ 54,000,000 |
GULF POWER CO | 6.45 % Preference stock | ||
Cumulative preferred stock | ||
Preference stock | 0 | 44,000,000 |
GULF POWER CO | 5.6% Preference Stock | ||
Cumulative preferred stock | ||
Preference stock | 0 | 49,000,000 |
GULF POWER CO | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Maturity | ||
2,017 | 0 | 87,000,000 |
GULF POWER CO | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Maturity | ||
2,022 | 100,000,000 | 100,000,000 |
GULF POWER CO | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Seven to Two Thousand Forty Four [Member] | ||
Maturity | ||
After Five Years | 715,000,000 | 415,000,000 |
GULF POWER CO | Maturity of Pollution Control Revenue Bonds 2023 through 2049 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 190,000,000 | 190,000,000 |
GULF POWER CO | Pollution control revenue bonds due 2023 through 2049 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 37,000,000 | 37,000,000 |
GULF POWER CO | Pollution control revenue bonds variable rate due 2022 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 4,000,000 | 4,000,000 |
GULF POWER CO | Pollution control revenue bonds due 2022-2042 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 78,000,000 | 78,000,000 |
MISSISSIPPI POWER CO | ||
Maturity | ||
2,017 | 0 | 35,000,000 |
2,018 | 50,000,000 | 50,000,000 |
2,019 | 125,000,000 | 125,000,000 |
After Five Years | 630,000,000 | 630,000,000 |
Total long-term notes payable | 1,705,000,000 | 2,040,000,000 |
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 83,000,000 | 83,000,000 |
Total other long-term debt | 353,000,000 | 904,000,000 |
Capitalized lease obligations | 0 | 74,000,000 |
Unamortized debt premium | 36,000,000 | 45,000,000 |
Unamortized debt discount | (1,000,000) | (2,000,000) |
Unamortized debt issuance expense | (7,000,000) | (8,000,000) |
Total long-term debt (annual interest requirement — $1.8 billion) | 2,086,000,000 | 3,053,000,000 |
Less amount due within one year | 989,000,000 | 629,000,000 |
Long-term debt excluding amount due within one year | $ 1,097,000,000 | $ 2,424,000,000 |
Percent capitalization | 44.10% | 44.90% |
Cumulative preferred stock | ||
Total redeemable preferred stock - percent capitalization | 1.30% | 0.60% |
Preferred stock | $ 33,000,000 | $ 33,000,000 |
Common Stockholders' Equity: | ||
Common stock | 38,000,000 | 38,000,000 |
Paid-in capital | 4,529,000,000 | 3,525,000,000 |
Retained earnings | (3,205,000,000) | (616,000,000) |
Accumulated other comprehensive loss | (4,000,000) | (4,000,000) |
Total common stockholders' equity | $ 1,358,000,000 | $ 2,943,000,000 |
Total common stockholders' equity - percent capitalization | 54.60% | 54.50% |
Total stockholders' equity | $ 1,358,000,000 | $ 2,943,000,000 |
Total capitalization | $ 2,488,000,000 | $ 5,400,000,000 |
Percent capitalization | 100.00% | 100.00% |
MISSISSIPPI POWER CO | Adjustable Rate Loans | ||
Maturity | ||
2,018 | $ 900,000,000 | $ 1,200,000,000 |
MISSISSIPPI POWER CO | Plant Daniel revenue bonds (7.13%) due 2021 | ||
Pollution control revenue bonds — | ||
Plant Daniel revenue bonds (7.13%) due 2021 | 270,000,000 | 270,000,000 |
MISSISSIPPI POWER CO | Pollution control revenue bonds due 2028 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 43,000,000 | 43,000,000 |
MISSISSIPPI POWER CO | Maturity Of Pollution Control Bonds 2017 | ||
Pollution control revenue bonds — | ||
Long-term pollution control bonds | 40,000,000 | 40,000,000 |
MISSISSIPPI POWER CO | Maturity of Long-Term Debt Payable To Parent Company Period One | ||
Pollution control revenue bonds — | ||
Long-term debt due to parent company | 0 | 551,000,000 |
SOUTHERN Co GAS | ||
Maturity | ||
2,018 | 155,000,000 | |
2,019 | 350,000,000 | |
2,020 | 0 | |
2,021 | 330,000,000 | |
2,022 | 93,000,000 | |
After Five Years | 4,600,000,000 | |
Total long-term notes payable | 3,887,000,000 | |
Pollution control revenue bonds — | ||
Gas facility revenue bonds | 200,000,000 | 200,000,000 |
Total other long-term debt | 1,225,000,000 | 825,000,000 |
Unamortized fair value adjustment of long-term debt | 525,000,000 | 578,000,000 |
Unamortized debt (discount), net | (17,000,000) | (9,000,000) |
Total long-term debt (annual interest requirement — $1.8 billion) | 6,048,000,000 | 5,281,000,000 |
Less amount due within one year | 157,000,000 | 22,000,000 |
Long-term debt excluding amount due within one year | $ 5,891,000,000 | $ 5,259,000,000 |
Percent capitalization | 39.50% | 36.60% |
Cumulative preferred stock | ||
Redeemable noncontrolling interests | $ 0 | |
Common Stockholders' Equity: | ||
Paid-in capital | $ 9,214,000,000 | 9,095,000,000 |
Retained earnings | (212,000,000) | (12,000,000) |
Accumulated other comprehensive loss | 20,000,000 | 26,000,000 |
Total common stockholders' equity | $ 9,022,000,000 | $ 9,109,000,000 |
Total common stockholders' equity - percent capitalization | 60.50% | 63.40% |
Total stockholders' equity | $ 9,022,000,000 | $ 9,109,000,000 |
Total capitalization | $ 14,913,000,000 | $ 14,368,000,000 |
Percent capitalization | 100.00% | 100.00% |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Maturity | ||
2,017 | $ 0 | $ 22,000,000 |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2018 | ||
Maturity | ||
2,018 | 155,000,000 | 155,000,000 |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2019 | ||
Maturity | ||
2,019 | 300,000,000 | 300,000,000 |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Maturity | ||
2,021 | 330,000,000 | 330,000,000 |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2022 | ||
Maturity | ||
2,022 | 46,000,000 | 46,000,000 |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt After Year Five | ||
Maturity | ||
After Five Years | 3,484,000,000 | 3,034,000,000 |
SOUTHERN Co GAS | Long Term Senior Notes | ||
Maturity | ||
Total long-term notes payable | 4,315,000,000 | |
SOUTHERN Co GAS | First Mortgage Bonds Due 2019 | ||
Pollution control revenue bonds — | ||
First mortgage bonds | 50,000,000 | 50,000,000 |
SOUTHERN Co GAS | First Mortgage Bonds Due 2023 to 2057 | ||
Pollution control revenue bonds — | ||
First mortgage bonds | 975,000,000 | 575,000,000 |
SOUTHERN Co GAS | Maturity Of Gas Facility Revenue Bonds Due 2022 | ||
Pollution control revenue bonds — | ||
Gas facility revenue bonds | 47,000,000 | 47,000,000 |
SOUTHERN Co GAS | Maturity Of Gas Facility Revenue Bonds Due 2024 to 2033 | ||
Pollution control revenue bonds — | ||
Gas facility revenue bonds | $ 153,000,000 | $ 153,000,000 |
Consolidated Statements of Ca11
Consolidated Statements of Capitalization (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Total long-term debt (annual interest requirement — $) | $ 1,800 | |
Annual dividend requirement | $ 0 | |
Common stock, par value per share (in dollars per share) | $ 5 | $ 5 |
Common stock, shares authorized | 1,500,000,000 | 1,500,000,000 |
Common stock, shares issued | 1,000,000,000 | 991,000,000 |
Treasury shares | 900,000 | 800,000 |
Redeemable Preferred Stock, $1 par value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
Redeemable cumulative preferred stock, shares authorized | 28,000,000 | 28,000,000 |
Redeemable cumulative preferred stock, shares outstanding | 0 | 2,000,000 |
Redeemable Preferred Stock, $1 par value | Cumulative Preferred Stock | ||
Dividend rate, minimum | 0.00% | 5.83% |
Redeemable Preferred Stock, $100 par or stated value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Redeemable cumulative preferred stock, shares authorized | 20,000,000 | 20,000,000 |
Redeemable cumulative preferred stock, shares outstanding | 1,000,000 | 1,000,000 |
Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock | ||
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 (in dollars per share) | $ 0 | $ 25 |
Preference Stock , $100 par or stated value | ||
Dividend rate, minimum | 0.00% | 5.60% |
Dividend rate, maximum | 0.00% | 6.50% |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Preference stock, shares outstanding | 0 | 4,000,000 |
Preference Stock, $1 par value | ||
Dividend rate, minimum | 0.00% | 6.45% |
Dividend rate, maximum | 0.00% | 6.50% |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
Preference stock, shares authorized | 65,000,000 | 65,000,000 |
Preference stock, shares outstanding | 0 | 8,000,000 |
Redeemable Preferred Stock | ||
Annual dividend requirement | $ 16 | $ 6 |
Noncumulative Preferred Stock | ||
Dividend rate, minimum | 0.00% | 6.00% |
Dividend rate, maximum | 0.00% | 6.13% |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
Preference stock, shares authorized | 60,000,000 | 60,000,000 |
Preference stock, shares outstanding | 0 | 2,000,000 |
Maturity of Pollution Control Revenue Bonds 2019 | ||
Fixed stated interest rate of debt obligation | 4.55% | |
Pollution Control Revenue Bonds Due 2021 | ||
Fixed stated interest rate of debt obligation | 7.13% | |
Maturity Of First Mortgage Bonds Due 2019 | ||
Fixed stated interest rate of debt obligation | 4.70% | |
Maturity Of Gas Facility Revenue Bonds Due 2022 to 2033 | ||
Fixed stated interest rate of debt obligation | 1.71% | |
Affiliate trusts, variable rate, due 2042 | ||
Fixed stated interest rate of debt obligation | 4.44% | |
Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt After Year Five | ||
Fixed stated interest rate of debt obligation | 3.75% | |
ALABAMA POWER CO | ||
Total long-term debt (annual interest requirement — $) | $ 305 | |
Annual dividend requirement | $ 25 | |
Common stock, par value per share (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 |
ALABAMA POWER CO | Redeemable Preferred Stock, $1 par value | ||
Dividend rate, minimum | 5.00% | 5.83% |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
Redeemable cumulative preferred stock, shares authorized | 27,500,000 | 27,500,000 |
Redeemable cumulative preferred stock, shares outstanding | 10,000,000 | 1,520,000 |
ALABAMA POWER CO | Redeemable Preferred Stock, $100 par or stated value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Redeemable cumulative preferred stock, shares authorized | 3,850,000 | 3,850,000 |
Redeemable cumulative preferred stock, shares outstanding | 475,115 | 475,115 |
ALABAMA POWER CO | Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock | ||
Dividend rate, minimum | 4.20% | 4.20% |
Dividend rate, maximum | 4.92% | 4.92% |
ALABAMA POWER CO | Redeemable Preferred Stock, $25 stated value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
ALABAMA POWER CO | Preference Stock, $1 par value | ||
Dividend rate, minimum | 6.45% | 6.45% |
Dividend rate, maximum | 6.50% | 6.50% |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
ALABAMA POWER CO | Redeemable Preferred Stock | ||
Annual dividend requirement | $ 15 | |
ALABAMA POWER CO | Noncumulative Preferred Stock | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
Preference stock, shares authorized | 40,000,000 | 40,000,000 |
Preference stock, shares outstanding | 0 | 8,000,000 |
ALABAMA POWER CO | Affiliate trusts, variable rate, due 2042 | ||
Fixed stated interest rate of debt obligation | 4.44% | 4.44% |
ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt 2019 | ||
Fixed stated interest rate of debt obligation | 5.125% | 5.125% |
ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 3.375% | 3.375% |
GEORGIA POWER CO | ||
Fixed stated interest rate of debt obligation | 2.00% | |
Total long-term debt (annual interest requirement — $) | $ 437 | |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Preference stock, shares outstanding | 0 | |
Common stock, shares outstanding | 9,261,500 | 9,261,500 |
GEORGIA POWER CO | Noncumulative Preferred Stock, $25 par value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
Dividend rate | 6.125% | 6.125% |
Preference stock, shares authorized | 50,000,000 | 50,000,000 |
Preference stock, shares outstanding | 1,800,000 | 1,800,000 |
GEORGIA POWER CO | Noncumulative Preferred Stock, $100 par value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Dividend rate | 6.50% | 6.50% |
Preference stock, shares authorized | 15,000,000 | 15,000,000 |
Preference stock, shares outstanding | 2,250,000 | 2,250,000 |
GEORGIA POWER CO | Maturity Of Pollution Control Bonds Variable Rate Due 2018 | ||
Fixed stated interest rate of debt obligation | 1.84% | |
GEORGIA POWER CO | Maturity of Long Term Senior Notes And Debt 2017 | ||
Fixed stated interest rate of debt obligation | 5.70% | 5.70% |
GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2019 | ||
Fixed stated interest rate of debt obligation | 4.25% | 4.25% |
GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 2.40% | 2.40% |
GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 2.85% | |
GULF POWER CO | ||
Total long-term debt (annual interest requirement — $) | $ 48 | |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Preference stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares outstanding | 7,392,717 | 5,642,717 |
GULF POWER CO | Redeemable Preferred Stock, $1 par value | ||
Redeemable cumulative preferred stock, shares outstanding | 0 | |
GULF POWER CO | Redeemable Preferred Stock, $100 par or stated value | ||
Redeemable cumulative preferred stock, shares authorized | 0 | |
GULF POWER CO | Preference Stock , $100 par or stated value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Preference stock, shares outstanding | 0 | 550,000 |
GULF POWER CO | Preference Stock Type Three | ||
Preference stock, shares outstanding | 0 | 450,000 |
GULF POWER CO | Preference Stock Type Four | ||
Preference stock, shares outstanding | 0 | 500,000 |
GULF POWER CO | Preference Stock, $1 par value | ||
Preference stock, shares authorized | 10,000,000 | 10,000,000 |
GULF POWER CO | Noncumulative Preferred Stock | ||
Preference stock, shares outstanding | 0 | |
GULF POWER CO | Maturity of Pollution Control Bonds Period One [Member] | ||
Fixed stated interest rate of debt obligation | 2.10% | |
GULF POWER CO | Pollution control revenue bonds variable rate due 2022 | ||
Fixed stated interest rate of debt obligation | 1.83% | |
GULF POWER CO | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 4.75% | 4.75% |
GULF POWER CO | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 3.10% | |
GULF POWER CO | 6.0% preference stock | Preference Stock , $100 par or stated value | ||
Fixed stated interest rate of debt obligation | 0.00% | 6.00% |
GULF POWER CO | 6.45% preference stock | Preference Stock , $100 par or stated value | ||
Fixed stated interest rate of debt obligation | 0.00% | 6.45% |
GULF POWER CO | 5.6% Preference Stock | Preference Stock , $100 par or stated value | ||
Fixed stated interest rate of debt obligation | 0.00% | 5.60% |
MISSISSIPPI POWER CO | ||
Total long-term debt (annual interest requirement — $) | $ 86 | |
Dividend rate, minimum | 4.40% | 4.40% |
Dividend rate, maximum | 5.25% | 5.25% |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Redeemable cumulative preferred stock, shares authorized | 1,244,139 | 1,244,139 |
Redeemable cumulative preferred stock, shares outstanding | 334,210 | 334,210 |
Annual dividend requirement | $ 2 | |
Common stock, shares authorized | 1,130,000 | 1,130,000 |
Common stock, shares outstanding | 1,121,000 | 1,121,000 |
MISSISSIPPI POWER CO | Maturity of Long Term Notes Payable Variable Rate Due 2018 | ||
Fixed stated interest rate of debt obligation | 3.05% | |
MISSISSIPPI POWER CO | 2028 | ||
Fixed stated interest rate of debt obligation | 5.15% | 5.15% |
MISSISSIPPI POWER CO | Plant Daniel revenue bonds (7.13%) due 2021 | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
MISSISSIPPI POWER CO | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Fixed stated interest rate of debt obligation | 5.60% | 5.60% |
MISSISSIPPI POWER CO | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 1.63% | 1.63% |
MISSISSIPPI POWER CO | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 5.55% | 5.55% |
MISSISSIPPI POWER CO | Maturity of Long-Term Debt Payable to Parent Company | ||
Fixed stated interest rate of debt obligation | 2.27% | 2.27% |
SOUTHERN Co GAS | ||
Total long-term debt (annual interest requirement — $) | $ 241 | |
Common stock, par value per share (in dollars per share) | $ 0.01 | $ 10,000 |
Common stock, shares authorized | 100,000,000 | 100 |
Common stock, shares outstanding | 100 | 100 |
SOUTHERN Co GAS | First Mortgage Bonds Due 2019 | ||
Fixed stated interest rate of debt obligation | 4.70% | |
SOUTHERN Co GAS | Maturity Of Gas Facility Revenue Bonds Due 2022 | ||
Fixed stated interest rate of debt obligation | 1.71% | |
SOUTHERN Co GAS | Maturity Of Gas Facility Revenue Bonds Due 2024 to 2033 | ||
Fixed stated interest rate of debt obligation | 1.71% | |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Fixed stated interest rate of debt obligation | 7.20% | |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 3.50% | |
SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2019 | ||
Fixed stated interest rate of debt obligation | 5.25% | |
Minimum | Maturity of Pollution Control Revenue Bonds 2022 | ||
Fixed stated interest rate of debt obligation | 2.10% | |
Minimum | Maturity of Pollution Control Revenue Bonds 2023 through 2049 | ||
Fixed stated interest rate of debt obligation | 1.15% | |
Minimum | Pollution Control Revenue Bonds Due 2017 | ||
Fixed stated interest rate of debt obligation | 2.45% | |
Minimum | Pollution Control Revenue Bonds Due 2022 to 2053 | ||
Fixed stated interest rate of debt obligation | 1.59% | |
Minimum | Pollution Control Revenue Bonds Due 2021 | ||
Fixed stated interest rate of debt obligation | 1.86% | |
Minimum | First Mortgage Bonds Due 2023 to 2033 | ||
Fixed stated interest rate of debt obligation | 2.66% | |
Minimum | Junior Subordinated Notes Due 2076 | ||
Fixed stated interest rate of debt obligation | 5.00% | |
Minimum | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Fixed stated interest rate of debt obligation | 1.30% | |
Minimum | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 1.50% | |
Minimum | Maturity of Long Term Senior Notes and Debt 2019 | ||
Fixed stated interest rate of debt obligation | 1.85% | |
Minimum | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 2.00% | |
Minimum | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 2.35% | |
Minimum | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 1.00% | |
Minimum | Maturity of Long Term Senior Notes and Debt After Year Five | ||
Fixed stated interest rate of debt obligation | 1.85% | |
Minimum | Maturity Of FFB Loans Due 2020 | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | Maturity Of FFB Loans Due 2021 | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | Maturity Of Loans Due Two Thousand Twenty Two | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | Maturity Of Loans Due Two Thousand Twenty Two To Two Thousand Forty Four [Member] | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Fixed stated interest rate of debt obligation | 1.82% | |
Minimum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 2.29% | |
Minimum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 2.04% | |
Minimum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 2.55% | |
Minimum | ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt 2021-2045 | ||
Fixed stated interest rate of debt obligation | 2.80% | 2.80% |
Minimum | ALABAMA POWER CO | Pollution control revenue bonds due 2034 | ||
Fixed stated interest rate of debt obligation | 1.625% | 1.625% |
Minimum | ALABAMA POWER CO | Pollution Control Revenue Bonds Variable Rate Due 2024 - 2038 | ||
Fixed stated interest rate of debt obligation | 1.70% | 1.70% |
Minimum | ALABAMA POWER CO | Maturity Of Pollution Control Bonds 2017 | ||
Fixed stated interest rate of debt obligation | 0.77% | 0.77% |
Minimum | ALABAMA POWER CO | Maturity Of Pollution Control Bonds 2021 | ||
Fixed stated interest rate of debt obligation | 1.86% | 1.86% |
Minimum | ALABAMA POWER CO | Maturity of Long Term Senior Notes And Debt 2017 | ||
Fixed stated interest rate of debt obligation | 5.50% | 5.50% |
Minimum | ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 3.95% | 3.95% |
Minimum | ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 5.875% | |
Minimum | ALABAMA POWER CO | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 2.55% | 2.55% |
Minimum | GEORGIA POWER CO | FFB Loans Due 2022 to 2044 | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2022 to 2043 | ||
Fixed stated interest rate of debt obligation | 3.25% | 2.85% |
Minimum | GEORGIA POWER CO | Pollution control revenue bonds due 2022 - 2049 | ||
Fixed stated interest rate of debt obligation | 1.38% | 1.38% |
Minimum | GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 1.95% | 1.95% |
Minimum | GEORGIA POWER CO | Variable rate, Due 2022-2053 | ||
Fixed stated interest rate of debt obligation | 1.59% | |
Minimum | GEORGIA POWER CO | Maturity Of FFB Loans Due 2020 | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | GEORGIA POWER CO | Maturity Of FFB Loans Due 2021 | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | GEORGIA POWER CO | Maturity Of Loans Due Two Thousand Twenty Two | ||
Fixed stated interest rate of debt obligation | 2.57% | 2.57% |
Minimum | GULF POWER CO | 2020-2051 | ||
Fixed stated interest rate of debt obligation | 3.30% | 3.10% |
Minimum | GULF POWER CO | Pollution control revenue bonds due 2022 - 2049 | ||
Fixed stated interest rate of debt obligation | 1.15% | 1.15% |
Minimum | GULF POWER CO | Pollution control revenue bonds due 2022-2042 | ||
Fixed stated interest rate of debt obligation | 1.85% | |
Minimum | GULF POWER CO | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 2.93% | 2.93% |
Minimum | MISSISSIPPI POWER CO | Maturity of Long Term Senior Notes and Debt 2035 to 2042 | ||
Fixed stated interest rate of debt obligation | 4.25% | 1.63% |
Minimum | MISSISSIPPI POWER CO | Maturity Of Pollution Control Bonds 2017 | ||
Fixed stated interest rate of debt obligation | 2.45% | 0.83% |
Minimum | SOUTHERN Co GAS | First Mortgage Bonds Due 2023 to 2057 | ||
Fixed stated interest rate of debt obligation | 2.66% | |
Minimum | SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 3.50% | |
Minimum | SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 8.55% | |
Minimum | SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt After Year Five | ||
Fixed stated interest rate of debt obligation | 2.45% | |
Maximum | Maturity of Pollution Control Revenue Bonds 2022 | ||
Fixed stated interest rate of debt obligation | 2.35% | |
Maximum | Maturity of Pollution Control Revenue Bonds 2023 through 2049 | ||
Fixed stated interest rate of debt obligation | 5.15% | |
Maximum | Pollution Control Revenue Bonds Due 2017 | ||
Fixed stated interest rate of debt obligation | 2.50% | |
Maximum | Pollution Control Revenue Bonds Due 2022 to 2053 | ||
Fixed stated interest rate of debt obligation | 1.88% | |
Maximum | Pollution Control Revenue Bonds Due 2021 | ||
Fixed stated interest rate of debt obligation | 1.87% | |
Maximum | First Mortgage Bonds Due 2023 to 2033 | ||
Fixed stated interest rate of debt obligation | 6.58% | |
Maximum | Junior Subordinated Notes Due 2076 | ||
Fixed stated interest rate of debt obligation | 6.25% | |
Maximum | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Fixed stated interest rate of debt obligation | 7.20% | |
Maximum | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 5.40% | |
Maximum | Maturity of Long Term Senior Notes and Debt 2019 | ||
Fixed stated interest rate of debt obligation | 5.55% | |
Maximum | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 4.75% | |
Maximum | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 9.10% | |
Maximum | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 8.70% | |
Maximum | Maturity of Long Term Senior Notes and Debt After Year Five | ||
Fixed stated interest rate of debt obligation | 7.30% | |
Maximum | Maturity Of FFB Loans Due 2020 | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | Maturity Of FFB Loans Due 2021 | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | Maturity Of Loans Due Two Thousand Twenty Two | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | Maturity Of Loans Due Two Thousand Twenty Two To Two Thousand Forty Four [Member] | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt In Last Twelve Months | ||
Fixed stated interest rate of debt obligation | 3.75% | |
Maximum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 3.05% | |
Maximum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt 2020 | ||
Fixed stated interest rate of debt obligation | 2.18% | |
Maximum | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 2.79% | |
Maximum | ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt 2021-2045 | ||
Fixed stated interest rate of debt obligation | 6.125% | 6.125% |
Maximum | ALABAMA POWER CO | Pollution control revenue bonds due 2034 | ||
Fixed stated interest rate of debt obligation | 1.85% | 1.85% |
Maximum | ALABAMA POWER CO | Pollution Control Revenue Bonds Variable Rate Due 2024 - 2038 | ||
Fixed stated interest rate of debt obligation | 1.87% | 1.87% |
Maximum | ALABAMA POWER CO | Maturity Of Pollution Control Bonds 2017 | ||
Fixed stated interest rate of debt obligation | 0.79% | 0.79% |
Maximum | ALABAMA POWER CO | Maturity Of Pollution Control Bonds 2021 | ||
Fixed stated interest rate of debt obligation | 1.87% | 0.86% |
Maximum | ALABAMA POWER CO | Maturity of Long Term Senior Notes And Debt 2017 | ||
Fixed stated interest rate of debt obligation | 5.55% | 5.55% |
Maximum | ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 2.38% | 2.38% |
Maximum | ALABAMA POWER CO | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 2.45% | |
Maximum | ALABAMA POWER CO | Adjustable Rate Loans | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 2.786% | 2.786% |
Maximum | GEORGIA POWER CO | FFB Loans Due 2022 to 2044 | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2022 to 2043 | ||
Fixed stated interest rate of debt obligation | 5.95% | 5.95% |
Maximum | GEORGIA POWER CO | Pollution control revenue bonds due 2022 - 2049 | ||
Fixed stated interest rate of debt obligation | 4.00% | 4.00% |
Maximum | GEORGIA POWER CO | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 5.40% | 5.40% |
Maximum | GEORGIA POWER CO | Variable rate, Due 2022-2053 | ||
Fixed stated interest rate of debt obligation | 1.88% | |
Maximum | GEORGIA POWER CO | Maturity Of FFB Loans Due 2020 | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | GEORGIA POWER CO | Maturity Of FFB Loans Due 2021 | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | GEORGIA POWER CO | Maturity Of Loans Due Two Thousand Twenty Two | ||
Fixed stated interest rate of debt obligation | 3.86% | 3.86% |
Maximum | GULF POWER CO | 2020-2051 | ||
Fixed stated interest rate of debt obligation | 5.10% | 5.75% |
Maximum | GULF POWER CO | Pollution control revenue bonds due 2022 - 2049 | ||
Fixed stated interest rate of debt obligation | 4.45% | 4.45% |
Maximum | GULF POWER CO | Pollution control revenue bonds due 2022-2042 | ||
Fixed stated interest rate of debt obligation | 1.88% | |
Maximum | GULF POWER CO | Maturity of Long Term Senior Notes and Debt 2018 | ||
Fixed stated interest rate of debt obligation | 5.90% | 5.90% |
Maximum | MISSISSIPPI POWER CO | Maturity of Long Term Senior Notes and Debt 2035 to 2042 | ||
Fixed stated interest rate of debt obligation | 5.40% | 5.40% |
Maximum | MISSISSIPPI POWER CO | Maturity Of Pollution Control Bonds 2017 | ||
Fixed stated interest rate of debt obligation | 2.50% | 0.87% |
Maximum | SOUTHERN Co GAS | First Mortgage Bonds Due 2023 to 2057 | ||
Fixed stated interest rate of debt obligation | 6.58% | |
Maximum | SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt in 2021 | ||
Fixed stated interest rate of debt obligation | 9.10% | |
Maximum | SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt 2022 | ||
Fixed stated interest rate of debt obligation | 8.70% | |
Maximum | SOUTHERN Co GAS | Maturity of Long Term Senior Notes and Debt After Year Five | ||
Fixed stated interest rate of debt obligation | 7.30% |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions | Total | Common Stock | Treasury | Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Preferred and Preference Stock of Subsidiaries | Noncontrolling Interests | ALABAMA POWER CO | ALABAMA POWER COCommon Stock | ALABAMA POWER COPaid-In Capital | ALABAMA POWER CORetained Earnings | ALABAMA POWER COAccumulated Other Comprehensive Income (Loss) | GEORGIA POWER CO | GEORGIA POWER COCommon Stock | GEORGIA POWER COPaid-In Capital | GEORGIA POWER CORetained Earnings | GEORGIA POWER COAccumulated Other Comprehensive Income (Loss) | GULF POWER CO | GULF POWER COCommon Stock | GULF POWER COPaid-In Capital | GULF POWER CORetained Earnings | GULF POWER COAccumulated Other Comprehensive Income (Loss) | MISSISSIPPI POWER CO | MISSISSIPPI POWER COCommon Stock | MISSISSIPPI POWER COPaid-In Capital | MISSISSIPPI POWER CORetained Earnings | MISSISSIPPI POWER COAccumulated Other Comprehensive Income (Loss) | SOUTHERN POWER CO | SOUTHERN POWER COCommon Stock | SOUTHERN POWER COPaid-In Capital | SOUTHERN POWER CORetained Earnings | SOUTHERN POWER COAccumulated Other Comprehensive Income (Loss) | SOUTHERN POWER COTotal Common Stockholder's Equity | SOUTHERN POWER CONoncontrolling Interests | [1] | SOUTHERN Co GAS | SOUTHERN Co GASCommon Stock | SOUTHERN Co GASTreasury | SOUTHERN Co GASPaid-In Capital | SOUTHERN Co GASRetained Earnings | SOUTHERN Co GASAccumulated Other Comprehensive Income (Loss) | SOUTHERN Co GASNoncontrolling Interests | |
Beginning balance (in shares) (Predecessor) at Dec. 31, 2014 | 119,647 | 217 | ||||||||||||||||||||||||||||||||||||||||||
Beginning balance (in shares) at Dec. 31, 2014 | 908,502 | 725 | 31,000 | 9,000 | 5,000 | 1,000 | 0 | |||||||||||||||||||||||||||||||||||||
Beginning balance (Predecessor) at Dec. 31, 2014 | $ 3,828 | $ 599 | $ (8) | $ 2,087 | $ 1,312 | $ (206) | $ 44 | |||||||||||||||||||||||||||||||||||||
Beginning balance at Dec. 31, 2014 | $ 20,926 | $ 4,539 | $ (26) | $ 5,955 | $ 9,609 | $ (128) | $ 756 | $ 221 | $ 5,752 | $ 1,222 | $ 2,304 | $ 2,255 | $ (29) | $ 10,421 | $ 398 | $ 6,196 | $ 3,835 | $ (8) | $ 1,309 | $ 483 | $ 560 | $ 267 | $ (1) | $ 2,084 | $ 38 | $ 2,612 | $ (559) | $ (7) | $ 1,971 | $ 0 | $ 1,176 | $ 573 | $ 3 | $ 1,752 | $ 219 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | Predecessor | 353 | 353 | ||||||||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 2,367 | 2,367 | 785 | 785 | 1,260 | 1,260 | 148 | 148 | (8) | (8) | ||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 215 | 215 | 215 | |||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | Predecessor | 20 | 20 | 0 | |||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | (2) | (2) | (3) | (3) | (7) | (7) | 1 | 1 | 1 | 1 | 1 | 1 | 1 | |||||||||||||||||||||||||||||||
Stock issued (in shares) | Predecessor | 221 | |||||||||||||||||||||||||||||||||||||||||||
Stock issued (in shares) | 6,571 | 2,599 | 1,000 | |||||||||||||||||||||||||||||||||||||||||
Stock issued | Predecessor | 12 | $ 1 | 11 | |||||||||||||||||||||||||||||||||||||||||
Stock issued | 256 | $ 33 | 223 | 20 | $ 20 | |||||||||||||||||||||||||||||||||||||||
Stock-based compensation (in shares) | Predecessor | 509 | |||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation | Predecessor | 4 | $ 3 | 1 | |||||||||||||||||||||||||||||||||||||||||
Stock-based compensation | 100 | 100 | ||||||||||||||||||||||||||||||||||||||||||
Stock repurchased, at cost | (115) | $ (115) | ||||||||||||||||||||||||||||||||||||||||||
Cash dividends on common stock | Predecessor | (244) | (244) | ||||||||||||||||||||||||||||||||||||||||||
Cash dividends on common stock | (1,959) | (1,959) | (571) | (571) | (1,034) | (1,034) | (130) | (130) | (131) | (131) | (131) | |||||||||||||||||||||||||||||||||
Preference stock redemption | (150) | (150) | ||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 567 | 567 | 567 | 567 | ||||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | Predecessor | (18) | (18) | ||||||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | (18) | (18) | (17) | (17) | ||||||||||||||||||||||||||||||||||||||||
Purchase of membership interests from noncontrolling interests | 0 | |||||||||||||||||||||||||||||||||||||||||||
Net income attributable to noncontrolling interests | Predecessor | 20 | 20 | ||||||||||||||||||||||||||||||||||||||||||
Net income attributable to noncontrolling interests | 12 | 12 | 12 | 12 | ||||||||||||||||||||||||||||||||||||||||
Other (in shares) | (28) | |||||||||||||||||||||||||||||||||||||||||||
Other | (2) | $ (1) | 4 | (7) | 3 | (1) | (8) | (8) | 1 | 1 | ||||||||||||||||||||||||||||||||||
Capital contributions from parent company | 37 | 37 | 79 | 79 | 7 | 7 | 281 | 281 | 646 | 646 | 646 | |||||||||||||||||||||||||||||||||
Ending balance (in shares) (Predecessor) at Dec. 31, 2015 | 120,377 | 217 | ||||||||||||||||||||||||||||||||||||||||||
Ending balance (in shares) at Dec. 31, 2015 | 915,073 | 3,352 | 31,000 | 9,000 | 6,000 | 1,000 | 0 | |||||||||||||||||||||||||||||||||||||
Ending balance (Predecessor) at Dec. 31, 2015 | 3,975 | $ 603 | $ (8) | 2,099 | 1,421 | (186) | 46 | |||||||||||||||||||||||||||||||||||||
Ending balance at Dec. 31, 2015 | 21,982 | $ 4,572 | $ (142) | 6,282 | 10,010 | (130) | 609 | 781 | 5,992 | $ 1,222 | 2,341 | 2,461 | (32) | 10,719 | $ 398 | 6,275 | 4,061 | (15) | 1,355 | $ 503 | 567 | 285 | 0 | 2,359 | $ 38 | 2,893 | (566) | (6) | 3,264 | $ 0 | 1,822 | 657 | 4 | 2,483 | 781 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | Predecessor | 131 | 131 | ||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | Predecessor | (35) | (35) | ||||||||||||||||||||||||||||||||||||||||||
Stock issued (in shares) | Predecessor | 95 | |||||||||||||||||||||||||||||||||||||||||||
Stock issued | Predecessor | 6 | $ 0 | 6 | |||||||||||||||||||||||||||||||||||||||||
Stock-based compensation (in shares) | Predecessor | 270 | |||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation | Predecessor | 30 | $ 2 | 28 | |||||||||||||||||||||||||||||||||||||||||
Cash dividends on common stock | Predecessor | (128) | (128) | ||||||||||||||||||||||||||||||||||||||||||
Reclassification from redeemable noncontrolling interests | Predecessor | (46) | (46) | ||||||||||||||||||||||||||||||||||||||||||
Ending balance (in shares) (Predecessor) at Jun. 30, 2016 | 120,742 | 217 | ||||||||||||||||||||||||||||||||||||||||||
Ending balance (Predecessor) at Jun. 30, 2016 | 3,933 | $ 605 | $ (8) | 2,133 | 1,424 | (221) | 0 | |||||||||||||||||||||||||||||||||||||
Ending balance at Jun. 30, 2016 | 8,001 | |||||||||||||||||||||||||||||||||||||||||||
Beginning balance (in shares) (Predecessor) at Dec. 31, 2015 | 120,377 | 217 | ||||||||||||||||||||||||||||||||||||||||||
Beginning balance (in shares) at Dec. 31, 2015 | 915,073 | 3,352 | 31,000 | 9,000 | 6,000 | 1,000 | 0 | |||||||||||||||||||||||||||||||||||||
Beginning balance (Predecessor) at Dec. 31, 2015 | 3,975 | $ 603 | $ (8) | 2,099 | 1,421 | (186) | 46 | |||||||||||||||||||||||||||||||||||||
Beginning balance at Dec. 31, 2015 | 21,982 | $ 4,572 | $ (142) | 6,282 | 10,010 | (130) | 609 | 781 | 5,992 | $ 1,222 | 2,341 | 2,461 | (32) | 10,719 | $ 398 | 6,275 | 4,061 | (15) | 1,355 | $ 503 | 567 | 285 | 0 | 2,359 | $ 38 | 2,893 | (566) | (6) | 3,264 | $ 0 | 1,822 | 657 | 4 | 2,483 | 781 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 2,448 | 2,448 | 822 | 822 | 1,330 | 1,330 | 131 | 131 | (50) | (50) | ||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 338 | 338 | 338 | |||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | (50) | (50) | 2 | 2 | 2 | 2 | 1 | 1 | 2 | 2 | 31 | 31 | 31 | |||||||||||||||||||||||||||||||
Stock issued (in shares) | 76,140 | 2,599 | ||||||||||||||||||||||||||||||||||||||||||
Stock issued | 3,758 | $ 380 | $ 115 | 3,263 | ||||||||||||||||||||||||||||||||||||||||
Stock-based compensation | 120 | 120 | ||||||||||||||||||||||||||||||||||||||||||
Cash dividends on common stock | (2,104) | (2,104) | (765) | (765) | (1,305) | (1,305) | (120) | (120) | (272) | (272) | (272) | |||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 618 | 618 | 618 | 618 | ||||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | (57) | (57) | (57) | (57) | ||||||||||||||||||||||||||||||||||||||||
Purchase of membership interests from noncontrolling interests | (129) | (129) | (129) | (129) | ||||||||||||||||||||||||||||||||||||||||
Net income attributable to noncontrolling interests | 32 | 32 | 32 | 32 | ||||||||||||||||||||||||||||||||||||||||
Other (in shares) | (66) | |||||||||||||||||||||||||||||||||||||||||||
Other | (6) | $ (4) | (4) | 2 | (1) | 1 | ||||||||||||||||||||||||||||||||||||||
Capital contributions from parent company | 272 | 272 | 610 | 610 | 22 | 22 | 632 | 632 | 1,850 | 1,850 | 1,850 | |||||||||||||||||||||||||||||||||
Ending balance (in shares) at Dec. 31, 2016 | 991,213 | 819 | 31,000 | 9,000 | 6,000 | 1,000 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Ending balance at Dec. 31, 2016 | 26,612 | $ 4,952 | $ (31) | 9,661 | 10,356 | (180) | 609 | 1,245 | 6,323 | $ 1,222 | 2,613 | 2,518 | (30) | 11,356 | $ 398 | 6,885 | 4,086 | (13) | 1,389 | $ 503 | 589 | 296 | 1 | 2,943 | $ 38 | 3,525 | (616) | (4) | 5,675 | $ 0 | 3,671 | 724 | 35 | 4,430 | 1,245 | 9,109 | $ 0 | $ 0 | 9,095 | (12) | 26 | 0 | ||
Beginning balance (in shares) (Predecessor) at Jun. 30, 2016 | 120,742 | 217 | ||||||||||||||||||||||||||||||||||||||||||
Beginning balance (Predecessor) at Jun. 30, 2016 | 3,933 | $ 605 | $ (8) | 2,133 | 1,424 | (221) | 0 | |||||||||||||||||||||||||||||||||||||
Beginning balance at Jun. 30, 2016 | 8,001 | |||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 114 | 114 | ||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | 26 | 26 | ||||||||||||||||||||||||||||||||||||||||||
Cash dividends on common stock | (126) | (126) | ||||||||||||||||||||||||||||||||||||||||||
Capital contributions from parent company | 1,094 | 1,094 | ||||||||||||||||||||||||||||||||||||||||||
Ending balance (in shares) at Dec. 31, 2016 | 991,213 | 819 | 31,000 | 9,000 | 6,000 | 1,000 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Ending balance at Dec. 31, 2016 | 26,612 | $ 4,952 | $ (31) | 9,661 | 10,356 | (180) | 609 | 1,245 | 6,323 | $ 1,222 | 2,613 | 2,518 | (30) | 11,356 | $ 398 | 6,885 | 4,086 | (13) | 1,389 | $ 503 | 589 | 296 | 1 | 2,943 | $ 38 | 3,525 | (616) | (4) | 5,675 | $ 0 | 3,671 | 724 | 35 | 4,430 | 1,245 | 9,109 | $ 0 | $ 0 | 9,095 | (12) | 26 | 0 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 842 | 842 | 848 | 848 | 1,414 | 1,414 | 135 | 135 | (2,590) | (2,590) | 243 | 243 | ||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 1,071 | 1,071 | 1,071 | |||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | (9) | (9) | 4 | 4 | 3 | 3 | (1) | (1) | (10) | (10) | (10) | (5) | (5) | |||||||||||||||||||||||||||||||
Stock issued (in shares) | 17,319 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||
Stock issued | 793 | $ 86 | $ 0 | 707 | 175 | $ 175 | ||||||||||||||||||||||||||||||||||||||
Stock-based compensation | 105 | 105 | ||||||||||||||||||||||||||||||||||||||||||
Cash dividends on common stock | (2,300) | (2,300) | (714) | (714) | (1,281) | (1,281) | (165) | (165) | (317) | (317) | (317) | (443) | (443) | |||||||||||||||||||||||||||||||
Other Comprehensive Income (Loss), Transfer from Service Company | [2] | (27) | (27) | (27) | ||||||||||||||||||||||||||||||||||||||||
Preference stock redemption | (609) | (609) | ||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 79 | 79 | 79 | 79 | ||||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | (122) | (122) | (122) | (122) | ||||||||||||||||||||||||||||||||||||||||
Net income attributable to noncontrolling interests | 44 | 44 | 44 | 44 | ||||||||||||||||||||||||||||||||||||||||
Reclassification from redeemable noncontrolling interests | 114 | 114 | ||||||||||||||||||||||||||||||||||||||||||
Reclassification from redeemable noncontrolling interests | 114 | 114 | ||||||||||||||||||||||||||||||||||||||||||
Other (in shares) | (110) | |||||||||||||||||||||||||||||||||||||||||||
Other | (21) | $ (5) | (4) | (13) | 1 | (5) | (5) | (4) | (4) | (7) | (7) | 1 | 1 | (7) | (7) | 0 | (7) | 0 | 1 | 2 | 0 | (1) | ||||||||||||||||||||||
Capital contributions from parent company | 373 | 373 | 443 | 443 | 5 | 5 | 1,004 | 1,004 | (2) | (2) | (2) | 117 | 117 | |||||||||||||||||||||||||||||||
Ending balance (in shares) at Dec. 31, 2017 | 1,008,532 | 929 | 31,000 | 9,000 | 6,000 | 1,000 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Ending balance at Dec. 31, 2017 | $ 25,528 | $ 5,038 | $ (36) | $ 10,469 | $ 8,885 | $ (189) | $ 0 | $ 1,361 | $ 6,829 | $ 1,222 | $ 2,986 | $ 2,647 | $ (26) | $ 11,931 | $ 398 | $ 7,328 | $ 4,215 | $ (10) | $ 1,531 | $ 678 | $ 594 | $ 259 | $ 0 | $ 1,358 | $ 38 | $ 4,529 | $ (3,205) | $ (4) | $ 6,498 | $ 0 | $ 3,662 | $ 1,478 | $ (2) | $ 5,138 | $ 1,360 | $ 9,022 | $ 0 | $ 0 | $ 9,214 | $ (212) | $ 20 | $ 0 | ||
[1] | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. | |||||||||||||||||||||||||||||||||||||||||||
[2] | Amount includes carry-over OCI balance of $27 million in connection with the Company becoming a participant to the Southern Company qualified pension plan. |
Consolidated Statements of St13
Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash dividends (in dollars per share) | $ 0.58 | $ 0.58 | $ 0.58 | $ 0.56 | $ 0.5600 | $ 0.5600 | $ 0.5600 | $ 0.5425 | $ 2.3000 | $ 2.2225 | $ 2.1525 |
Other comprehensive income (loss) | $ (9) | $ (50) | $ (2) | ||||||||
SOUTHERN POWER CO | |||||||||||
Other comprehensive income (loss) | $ (10) | $ 31 | $ 1 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
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 electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities. 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. Intercompany transactions have been eliminated in consolidation. The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. 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. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows. In 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million . Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required. Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term , as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs , energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019. Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. Regulatory Assets and Liabilities The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans $ 3,931 $ 3,959 (a,n) Asset retirement obligations-asset 1,133 1,080 (b,n) Deferred income tax charges 814 1,590 (b,p) Environmental remediation-asset 511 491 (j,n) Property damage reserves-asset 333 206 (i) Under recovered regulatory clause revenues 317 273 (g) Remaining net book value of retired assets 306 351 (o) Loss on reacquired debt 223 243 (c) Vacation pay 183 182 (f,n) Long-term debt fair value adjustment 138 155 (d) Deferred PPA charges 119 141 (e,n) Kemper County energy facility 88 201 (h) Other regulatory assets 511 487 (k) Deferred income tax credits (7,261 ) (219 ) (b,p) Other cost of removal obligations (2,684 ) (2,774 ) (b) Over recovered regulatory clause revenues (155 ) (203 ) (g) Property damage reserves-liability (135 ) (177 ) (l) Other regulatory liabilities (266 ) (120 ) (m) Total regulatory assets (liabilities), net $ (1,894 ) $ 5,866 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 other cost of removal obligations 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 80 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (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) Recovered over the remaining life of the original debt issuances, which range up to 21 years . For additional information see Note 12 under " Southern Company – Merger with Southern Company Gas ." (e) Recovered over the life of the PPA for periods up to six 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 or other applicable regulatory agencies over periods generally not exceeding 10 years . (h) Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years , respectively. For additional information, see Note 3 under " Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement ." (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under " Regulatory Matters – Georgia Power – Storm Damage Recovery " for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years . (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years . (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 48 years . (p) As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under " Regulatory Matters " and Note 5 for additional information. In the event that a portion of a traditional electric operating company's or a natural gas distribution utility'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 electric operating company or natural gas distribution utility 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 " Regulatory Matters – Alabama Power ," " – Georgia Power ," " – Gulf Power ," and " – Southern Company Gas " and " Kemper County Energy Facility " 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. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. For the traditional electric operating companies, 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 tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months . Programs of this type include weather normalization adjustments, revenue normalization mechanisms, and revenue true-up adjustments and are referred to as alternative revenue programs. Southern Company's electric utility subsidiaries and Southern Company Gas 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. Cost of Natural Gas Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively. 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 electric operating companies and Southern Company Gas 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. Under current tax law, 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. 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. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2017 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which would result in income tax benefits in the future, if utilized. See Note 5 under " Current and Deferred Income Taxes – Tax Credit Carryforwards " and " – Net Operating Loss " for additional information. 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: 2017 2016 (in millions) Electric utilities: Generation $ 51,279 $ 48,836 Transmission 11,562 11,156 Distribution 19,239 18,418 General 4,276 4,629 Plant acquisition adjustment 126 126 Electric utility plant in service 86,482 83,165 Natural gas distribution utilities: Transportation and distribution 13,078 11,996 Utility plant in service 99,560 95,161 Information technology equipment and software 752 544 Communications equipment 456 424 Storage facilities 1,598 1,463 Other 1,176 824 Total other plant in service 3,982 3,255 Total plant in service $ 103,542 $ 98,416 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. In accordance with their respective state PSC orders, Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle, which ranges from 18 to 24 months . 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, 2017 2016 (in millions) Office buildings $ 216 $ 61 Nitrogen plant (*) — 83 Computer-related equipment 51 63 Gas pipeline 6 6 Less: Accumulated amortization (72 ) (69 ) Balance, net of amortization $ 201 $ 144 (*) Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information. The amount of non-cash property additions recognized for the years ended December 31, 2017 , 2016 , and 2015 was $985 million , $1.3 billion , and $844 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, 2017 , 2016 , and 2015 was $162 million , $18 million , and $13 million , 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 2.9% in 2017 and 3.0% in each of 2016 and 2015 . Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $30.8 billion and $29.3 billion at December 31, 2017 and 2016 , 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 related to natural gas-fired facilities are 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. Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under " Regulatory Matters – Gulf Power – Retail Base Rate Cases " for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from two to 65 years . Accumulated depreciation for other plant in service totaled $673 million and $550 million at December 31, 2017 and 2016 , respectively. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other 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 and amounts to be recovered are reflected in the balance sheet as a regulatory asset. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric 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 as 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 |
ALABAMA POWER CO | |
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 Southern Company, which is the parent company of the Company and three other traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service 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 develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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 Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. 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 $479 million , $460 million , and $438 million during 2017 , 2016 , and 2015 , 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. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment. 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 $248 million , $249 million , and $243 million during 2017 , 2016 , and 2015 , 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 totaled $9 million in 2017 , $13 million in 2016 , and $11 million in 2015 . Mississippi Power also reimbursed the Company for any direct fuel purchases delivered from one of the Company's transfer facilities. There were no such fuel purchases in 2017 and 2016 and $8 million in 2015 . See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. Under a related tariff, the Company received $11 million in 2017, $12 million in 2016, and $14 million in 2015 and expects to recover a total of approximately $61 million from 2018 through 2023 from Gulf Power. In September 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were approximately $9 million in 2017 and $2 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016 . The Company has agreements with PowerSecure for services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs for these services amounted to approximately $11 million for 2017 and were immaterial for 2016. 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 2017 , 2016 , or 2015 . Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional electric 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans $ 946 $ 947 (i,j) Deferred income tax charges 240 526 (a,k,n) Regulatory clauses 142 — (m) Vacation pay 70 69 (c,j) Loss on reacquired debt 62 68 (b) Nuclear outage 56 70 (d) Remaining net book value of retired assets 54 69 (l) Under/(over) recovered regulatory clause revenues 53 76 (d) Other regulatory assets 51 50 (f) Fuel-hedging losses 7 1 (e,j) Deferred income tax credits (2,082 ) (65 ) (a,n) Other cost of removal obligations (609 ) (684 ) (a) Natural disaster reserve (38 ) (69 ) (h) Asset retirement obligations (33 ) 12 (a) Other regulatory liabilities (7 ) (23 ) (e,g) Total regulatory assets (liabilities), net $ (1,088 ) $ 1,047 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 credits are amortized over the related property lives, which may range up to 50 years . Asset retirement and other cost of 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 . See Note 3 under "Retail Regulatory Matters" for additional information. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half 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 (to be recovered over the next 12 months ), 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 fuel-hedging gains. 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 $13 million for 2017 and $16 million for 2016 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 up to 11 years . (m) Established per an order from the Alabama PSC issued on February 17, 2017 and will be amortized concurrently with the effective date of the Company's next depreciation study. See Note 3 under "Retail Regulatory Matters – Rate RSE" for additional information. (n) As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be established consistent with guidance provided by the Alabama PSC. See Note 5 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 and the Alabama PSC continuously monitor the under/over recovered balances. The Company 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 Compliance" 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. 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. 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: 2017 2016 (in millions) Generation $ 14,213 $ 13,551 Transmission 4,119 3,921 Distribution 7,034 6,707 General 1,948 1,840 Plant acquisition adjustment 12 12 Total plant in service $ 27,326 $ 26,031 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 2.9% in 2017 , 3% in 2016 , and 2.9% in 2015 . Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by 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 2016, the Company submitted an updated depreciation study to the FERC and received authorization to use the recommended rates beginning January 2017. The study was also provided to the Alabama PSC. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. 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, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, 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, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, 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: 2017 2016 (in millions) Balance at beginning of year $ 1,533 $ 1,448 Liabilities incurred — 5 Liabilities settled (26 ) (25 ) Accretion 77 73 Cash flow revisions 125 32 Balance at end of year $ 1,709 $ 1,533 The increase in liabilities incurred and cash flow revisions in 2017 is primarily due to updated cost estimates related to the closure of ash ponds and landfills. The increase in 2016 is primarily related to changes in ash pond closure strategy. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. 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, 2017 , investment securities in the Funds totaled $902 million , consisting of equity securities of $644 million , debt securities of $223 million , and $35 million of other securities. At December 31, 2016 , investment securities in the Funds totaled $790 million , consisting of equity securities of $552 million , debt securities of $208 million , and $30 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 $237 million , $351 million , and $438 million in 2017 , 2016 , and 2015 , respectively, all of which were reinvested. For 2017 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $125 million , which included $98 million related to unrealized gains on securities held in the Funds at December 31, 2017 . For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $76 million , which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million , which included $57 million related to unrealized losses on securities held in the Funds at December 31, 2015 . 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 through 2040 as 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: 2017 2016 (in millions) External trust funds $ 902 $ 790 Internal reserves 18 19 Total $ 920 $ 809 Site study cost is the estimate to decommission |
GEORGIA POWER CO | |
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 Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle Units 1 and 2, and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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. In 2015, the Company identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, the Company recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million . The Company evaluated the effects of this error on the interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, the Company determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required. Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to PPAs and cellular towers where the Company is the lessee and to outdoor lighting where the Company is the lessor. The Company is currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. 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 $625 million , $606 million , and $585 million in 2017 , 2016 , and 2015 , 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. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment. 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 $675 million , $666 million , and $681 million in 2017 , 2016 , and 2015 , respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information. The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $235 million , $265 million , and $179 million in 2017 , 2016 , and 2015 , respectively. See Note 6 under "Capital Leases" and 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 $11 million , $8 million , and $12 million in 2017 , 2016 , and 2015 , respectively. See Note 4 for additional information. In 2014, prior to Southern Company's acquisition of PowerSecure on May 9, 2016, the Company entered into agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. In October 2016, the two facilities began commercial operation. Payments of $119 million made by the Company to PowerSecure under the agreements since 2014 are included in utility plant in service at December 31, 2017 . On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $102 million in 2017 and $35 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016 . Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $22 million in 2017 and $10 million for the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016 . 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 2017 , 2016 , or 2015 . The traditional electric 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans $ 1,313 $ 1,348 (a, k) Asset retirement obligations 945 893 (b, k) Deferred income tax charges 521 681 (b, c, k) Storm damage reserves 333 206 (d) Remaining net book value of retired assets 146 166 (e) Loss on reacquired debt 127 137 (f, k) Other regulatory assets 119 97 (g) Vacation pay 91 91 (h, k) Other cost of removal obligations 40 3 (b) Cancelled construction projects 36 44 (i) Deferred income tax credits (3,248 ) (121 ) (b, c) Other regulatory liabilities (191 ) (39 ) (j, k) Total regulatory assets (liabilities), net $ 232 $ 3,506 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) 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 65 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $21 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022. (c) As a result of Tax Reform Legislation, these balances include $145 million of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 and $626 million of deferred income tax liabilities, neither of which are subject to normalization. The recovery and amortization of these amounts will be determined by the Georgia PSC. See Note 3 under "Retail Regulatory Matters – Rate Plans" and Note 5 for additional information. (d) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information. (e) Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. The net book value of Plant Mitchell Unit 3 at December 31, 2017 was $10 million , which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $4 million , and $31 million related to obsolete inventories of certain retired units is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information. (f) 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 35 years . (g) Comprised of several components including deferred nuclear outages, environmental remediation, building lease, demand-side management tariff under-recovery, and fuel-hedging losses. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months . The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $54 million at December 31, 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. Fuel-hedging losses are recovered through the Company's fuel cost recovery mechanism upon final settlement. (h) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (i) 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. (j) Comprised of certain customer refunds and fuel-hedging gains. As ordered by the Georgia PSC on January 11, 2018, approximately $188 million of the proceeds pursuant to the Toshiba Guarantee will be refunded to customers in 2018. Fuel-hedging gains are refunded through the Company's fuel cost recovery mechanism upon final settlement. See Note 3 under "Nuclear Construction" for additional information on the customer refunds related to the Toshiba Guarantee. (k) 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. 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, upon utilization, amortized to income as a credit to reduce depreciation over the average life of the related property. The Company had $87 million in federal ITCs at December 31, 2017 that will expire by 2037. State ITCs are recognized in the period in which the credits are generated. The Company had state investment and other tax credit carryforwards totaling $495 million at December 31, 2017 , which will expire between 2019 and 2028 and are expected to be fully utilized by 2026. 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: 2017 2016 (in millions) Generation $ 17,038 $ 16,668 Transmission 5,947 5,779 Distribution 9,978 9,553 General 1,870 1,813 Plant acquisition adjustment 28 28 Total plant in service $ 34,861 $ 33,841 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 2017 , 2.8% in 2016 , and 2.7% in 2015 . 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. Under the terms of the 2013 ARP, the Company amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual and recovery of other retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, amounts to be recovered are reflected in the balance sheets as a regulatory asset and any accumulated removal costs for future obligations are reflected in the balance sheets as a regulatory liability. The ARO liability primarily relates to the Company's ash ponds, landfills, and gypsum cells that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule). In addition, the Company has retirement obligations related to decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, 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: 2017 2016 (in millions) Balance at beginning of year $ 2,532 $ 1,916 Liabilities incurred 4 — Liabilities settled (120 ) (123 ) Accretion 89 77 Cash flow revisions 133 662 Balance at end of year $ 2,638 $ 2,532 In 2017 and 2016, the increases in cash flow revisions are primarily related to changes to the Company's closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities settled are primarily related to ash pond closure activity. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. 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, 2017 and 2016 , approximately $76 million and $56 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 $77 million and $58 million at December 31, 2017 and 2016 , respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a |
GULF POWER CO | |
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 Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), Inc. (PowerSecure), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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 Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to a PPA, cellular towers, and barges where the Company is the lessee and to outdoor lighting and power distribution equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. 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 $81 million , $80 million , and $81 million during 2017 , 2016 , and 2015 , 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. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment. 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 $11 million , $8 million , and $12 million and Mississippi Power $31 million , $26 million , and $27 million in 2017 , 2016 , and 2015 , respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. Total power purchased from affiliates through the power pool, included in purchased power in the statements of income, totaled $15 million , $16 million , and $35 million in 2017, 2016, and 2015, respectively. The Company has an agreement with Alabama Power under which Alabama Power made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. Payments by the Company to Alabama Power for the improvements were $11 million , $12 million , and $14 million in 2017 , 2016 , and 2015 , respectively, and are expected to be approximately $10 million annually for 2018 through 2023 , when the PPA expires. 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. In 2016, the Company purchased a turbine rotor assembly from Southern Power for $6.8 million . 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 2017 , 2016 , or 2015 . The traditional electric 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans, net $ 166 $ 160 (a,b) PPA charges 119 141 (b,c) Closure of ash ponds 80 75 (b,d) Remaining book value of retired assets 65 66 (e) Environmental remediation 52 44 (b,d) Other regulatory assets, net 36 18 (i) Deferred income tax charges 31 56 (f) Deferred return on transmission upgrades 25 25 (e) Fuel-hedging assets, net 21 24 (b,h) Loss on reacquired debt 17 18 (j) Asset retirement obligations, net 13 7 (b,f) Regulatory asset, offset to other cost of removal — 29 (e) Deferred income tax credits (458 ) (2 ) (g) Other cost of removal obligations (221 ) (278 ) (f) Property damage reserve (40 ) (40 ) (e) Over recovered regulatory clause revenues (11 ) (23 ) (k) Total regulatory assets (liabilities), net $ (105 ) $ 320 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) Not earning a return as offset in rate base by a corresponding asset or liability. (c) Recovered over the life of the PPA for periods up to six years . (d) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (e) Recorded and recovered or amortized as approved by the Florida PSC. (f) Asset retirement and removal assets and liabilities are recorded, and deferred income tax assets are recorded, recovered, and 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. (g) Deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years . Includes the deferred tax liabilities as a result of the Tax Reform Legislation. Amortization of $71 million of the deferred tax liabilities at December 31, 2017 is expected to be determined by the Florida PSC at a later date. See Notes 3 and 5 for additional information. (h) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which currently do not exceed four years . Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (i) Comprised primarily of under recovered regulatory clause revenues. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year . (j) 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 . (k) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . 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. 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: 2017 2016 (in millions) Generation $ 3,005 $ 3,001 Transmission 720 706 Distribution 1,282 1,241 General 188 191 Plant acquisition adjustment 1 1 Total plant in service $ 5,196 $ 5,140 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 3.5% for all years presented. 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 in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), the Company was allowed to reduce depreciation and record a regulatory asset in an aggregate amount up to $62.5 million between January 2014 and June 2017. See Note 3 under "Retail Regulatory Matters – Retail Base Rate Cases" for additional information. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. 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 facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and to the closure of an ash pond at Plant Scholz. In addition, the Company has retirement obligations related to combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, 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 on the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 136 $ 130 Liabilities incurred — 1 Liabilities settled (8 ) (1 ) Accretion 2 4 Cash flow revisions 12 2 Balance at end of year $ 142 $ 136 The cost estimates for AROs related to CCR are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure for those facilities impacted by the CCR Rule. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. Allowance for Funds Used During Construction 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, 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 all years presented. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 0.07% , 0.00% , and 10.8% for 2017 , 2016 , and 2015 , 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 million and $55 million . In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), the Company suspended further property damage reserve accruals effective April 2017. The Company may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve falls below zero . The Company accrued total expenses of $3.5 million in each of 2017 , 2016 , and 2015 . As of December 31, 2017 and 2016 , the balance in the Company's property damage reserve totaled approximately $40 million , which is included in other regulatory liabilities, deferred on 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. As authorized in the 2017 Rate Case Settlement Agreement, the Company may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million ( 75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00 /month for a 1,000 KWH residential customer unless the Company incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million . See Note 3 under "Retail Regulatory Matters – Retail Base Rate Cases" for additional details of the 2017 Rate Case 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 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 had a balance of $2.1 million and $1.4 million at December 31, 2017 , and 2016 , respectively. For 2017, $1.6 million and $0.5 million are included in other current liabilities and other deferred credits and liabilities on the balance sheet, respectively. For 2016, the $1.4 million balance is included in other current liabilities on the balance sheet. There were no liabilities in excess of the reserve balance at December 31, 2017 or 2016 . 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 recorded 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 on the balance sheets (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 |
MISSISSIPPI POWER CO | |
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 Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The Company is subject to regulation by the FERC and the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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 Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. 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 $140 million , $231 million , and $295 million during 2017 , 2016 , and 2015 , respectively. Cost allocation methodologies used by SCS prior to the repe al 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. See Note 7 under "Operating Leases" for additional information. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene Coun ty Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $9 million , $13 million , and $11 million in 2017 , 2016 , and 2015 , respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility. There were no fuel purchases in 2017 or 2016 . Fuel purchases were $8 million in 2015 . 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, whic h totaled $31 million , $26 million , and $27 million in 2017 , 2016 , and 2015 , respectively. See Note 4 for additional information. Total power purchased from affiliates through the power pool, included in purchased power in the statement of operations, totaled $16 million , $29 million , and $7 million in 2017 , 2016 , and 2015 , respectively. In June 2017, the Company received a capital contribution from Southern Company of $1.0 billion . The Company used a portion of the proceeds to repay all of the $591 million outstanding principal amount of promissory notes to Southern Company. See Note 6 for additional information. On September 15, 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible research and experimental (R&E) expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" 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 he rein, the Company neither provided nor received any material services to or from affiliates in 2017 , 2016 , or 2015 . The traditional electric operating companies, including the Company, and S outhern 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans – regulatory assets $ 174 $ 173 (a) Asset retirement obligations 95 83 (b) Kemper County energy facility 88 194 (c) Remaining net book value of retired assets 44 53 (d) Property tax 43 37 (e) Deferred charges related to income taxes 36 362 (d) Plant Daniel Units 3 and 4 36 33 (f) Other regulatory assets 28 28 (g) ECO carryforward 26 22 (h) Other regulatory liabilities — (1 ) (i) Deferred credits related to income taxes (377 ) (9 ) (j) Other cost of removal obligations (178 ) (170 ) (k) Property damage (57 ) (68 ) (l) Total regulatory assets (liabilities), net $ (42 ) $ 737 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) To be recovered upon completion of removal activities over a period approved by the Mississippi PSC. (c) Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered in rates over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." (d) Recovered over the related property lives up to 48 years. (e) Recovered through the ad valorem tax adjustment clause over a 12 -month period beg inning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. (f) Represents the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, which will be amortized over a 10 -year period beginning October 2021. (g) Comprised of vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. This amount also includes fuel-hedging assets and liabilities which 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 ECM. (h) Recovered through the ECO clause in the year following the deferral. (i) Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year. (j) This amount includes excess deferred income taxes primarily associated with Tax Reform Legislation of $375 million , of which $273 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $102 million related to unprotected (not subject to normalization) deferred income taxes to be amortized over a period approved by the Mississippi PSC or the FERC, as appropriate. Of the total excess deferred income taxes associated with Tax Reform Legislation, $129 million is associated with the Kemper County energy facility. The unprotected portion associated with the Kemper County energy facility is $54 million , of which $38 million is being amortized over eight years for retail as approved by the Mississippi PSC on February 6, 2018 and $16 million is wholesale-related. Currently, the Company is requesting eight -year amortization for the remaining portions of the unprotected deferred income taxes associated with Tax Reform Legislation in all of its retail and wholesale rate filings. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" and Note 5 for additional information. (k) Collected in advance from customers to remove assets upon their retirement. (l) For additional information, see Note 1 under "Provision for Property Damage." 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" and "Kemper County Energy Facility" for additional information. Government Grants In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants). Through December 31, 2017 , the Company has received grant funds of $382 million , of which $245 million of the Initial DOE Grants were used for the construction of the Kemper County energy facility, which is reflected in the Company's financial statements as a reduction to the Kemper County energy facility capital costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $2 million is expected to be received for allowable costs through December 31, 2017. See Note 3 under "Kemper County Energy Facility – 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 represent ed 19.3% of the Company's total operating revenues in 2017 and are largely subject to rolling 10 -year c ancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers. Except as described above for the Company's cost-based MRA electric tariff customers, the Company has a diversified base of customers and 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. T axes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. 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: 2017 2016 (in millions) Generation $ 2,801 $ 2,632 Transmission 737 712 Distribution 946 916 General 204 520 Plant acquisition adjustment 85 85 Total plant in service $ 4,773 $ 4,865 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 a portion of the railway track maintenance costs. The portion of railway track maintenance costs not charged to operations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. Depreciation, Depletion, and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.7% in 2017 , 4.2% in 2016 , and 4.7% in 2015 . The decrease in 2017 is primarily due to lower depreciation expense as a result of recording a loss on the lignite mine in June 2017. The decrease in the 2016 depreciation rate is primarily due to fully depreciating and retiring the ARO at Plant Watson, partially offset by the increase in depreciation for the Plant Daniel scrubbers for a full year. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. The Mississippi PSC approved the 2014 study, with new rates effective January 1, 2015. 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, except for the Kemper County energy facility combined cycle and related assets in service. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. 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 liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations 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 and certain wireless communication towers. 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 th e 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 e ither a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. Details of the AROs included in the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 179 $ 177 Liabilities incurred — 15 Liabilities settled (23 ) (23 ) Accretion 5 5 Cash flow revisions 13 5 Balance at end of year $ 174 $ 179 The increase in cash flow revisions in 2017 is primarily related to a revision in the closure date of the lignite mine ARO. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. Allowance for Funds Used During Construction 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, 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 6.7% , 6.5% , and 5.99% for the years ended December 31, 2017 , 2016 , and 2015 , respectively. AFUDC equity was $72 million , $124 million , a nd $110 million in 2017 , 2016 , and 2015 , respectively. The decrease in 2017 resulted from the Kemper IGCC project suspension in June 2017. 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. 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 exce ed $50,000 i s charged to the reserve. Every three years the Mississippi PSC, the 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. The Company made retail accruals of $3 million , $4 million , and $3 million for 2017 , 2016 , and 2015 , respectively. The Company also accrued $0.3 million annually in 2017 , 2016 , and 2015 for the wholesale jurisdiction. As of December 31, 2017 , the property damage reserve balances were $56 mill |
SOUTHERN POWER CO | |
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 Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, and other direct and indirect subsidiaries. The traditional electric 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) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Effective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations. The Company adopted the same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis. The preparation of consolidated 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 consolidated financial statements have been reclassified to conform to the current year presentation. The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation. Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment. Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements. Other In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. Affiliate Transactions Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million , $258 million , and $219 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015 . The 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. Prior to December 2017, the Company did not have employees and thus all employee-related charges were rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS totaled $218 million , $193 million , and $146 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Of these costs, $192 million , $173 million , and $138 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. 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. Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015. The Company also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in fuel expense on the consolidated statements of income. On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $25 million for the year ended December 31, 2017 and $7 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016. The Company and the traditional electric 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 electric 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 may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred. Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 for additional fair value information. 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. All capacity revenues are included in wholesale revenues. 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 additional information. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. Transmission revenues and other fees are recognized as earned as other operating revenues. 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 Company's top three customers for each of the years presented: 2017 2016 2015 Georgia Power 11.3 % 16.5 % 15.8 % Duke Energy Corporation 6.7 % 7.8 % 8.2 % Morgan Stanley Capital Group 4.5 % N/A N/A San Diego Gas & Electric Company N/A 5.7 % N/A Florida Power & Light Company N/A N/A 10.7 % Fuel Costs Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. Development Costs The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income. 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 current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs 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. In addition, certain projects are eligible for federal PTCs, which are recorded as an income tax benefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2017 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information. Property, Plant, and Equipment The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, 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. When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income. Depreciation The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are 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 generating facilities, which generally have estimated useful lives as follows: Generating facility Useful life Natural gas Up to 45 years Biomass Up to 40 years Solar Up to 35 years Wind Up to 30 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. Asset Retirement Obligations Asset retirement obligations (ARO) are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 11 for acquisitions during 2017 and 2016 which contributed to the increased liability. Details of the AROs included on the consolidated balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 64 $ 21 Liabilities incurred 6 42 Accretion 4 1 Cash flow revisions 4 — Balance at end of year $ 78 $ 64 Long-Term Service Agreements The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired 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 other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the consolidated 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 primarily of certain PPAs acquired, which are amortized over the term of the PPAs, which have a weighted average term of 19 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. Amortization expense for acquired PPAs was $25 million , $10 million , and $3 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, and is recorded in operating revenues. The estimated annual amortization expense is $25 million for each of the next five years. Transmission Receivables/Prepayments As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five -year period and the receivable/prepayments are reduced as payments or services are received. Restricted Cash The Company has restricted cash primarily related to certain acquisitions and construction projects. The aggregate amount of restricted cash at December 31, 2017 and 2016 was $11 million and $13 million , 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 Materials and supplies include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment. Fuel Inventory Fuel inventory, which is included in other current assets, includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several natural gas 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 also 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, electricity purchases and sales, and foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other") 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. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 9 for additional information regarding derivatives. The Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 or 2016. The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has 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. 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 of amounts included in net income. Accumulated OCI (loss) balances, net of tax effects, were as follows: Qualifying Hedges Pension and Other Postretirement Benefit Plans Accumulated Other Comprehensive Income (Loss) (in millions) Balance at December 31, 2016 $ 35 $ — $ 35 Current period change (10 ) — (10 ) Other comprehensive income transfer from SCS (*) — (27 ) (27 ) Balance at December 31, 2017 $ 25 $ (27 ) $ (2 ) (*) In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of OCI, net of tax of $9 million , was transferred from SCS. 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. |
SOUTHERN Co GAS | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General On July 1, 2016, Southern Company and Southern Company Gas (together with its subsidiaries, the Company) completed the Merger and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. In addition to the Company, Southern Company is the parent company of four traditional electric operating companies, Southern Power, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, Inc., and other direct and indirect subsidiaries. The Company is an energy services holding company whose primary business is the distribution of natural gas across seven states through its seven natural gas distribution utilities. The Company also is involved in several other businesses that are complementary to the distribution of natural gas. The traditional electric operating companies – Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power 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. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure, Inc. is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect the Company's investments in its subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for VIEs where the Company has an equity investment, but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The seven natural gas distribution utilities are subject to regulation by the regulatory agencies of each state in which they operate. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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. Pursuant to the Merger, Southern Company has pushed down the application of the acquisition method of accounting to the financial statements of the Company such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the financial statements of the Company for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout the financial statements and notes to the financial statements, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor." Certain predecessor period data presented in the financial statements has been modified or reclassified to conform to the presentation used by the Company's new parent company, Southern Company. Changes to the statements of income include classifying operating revenues as natural gas revenues and other revenues as well as classifying cost of goods sold as cost of natural gas and cost of other sales, and presenting interest expense and AFUDC on a gross basis. Changes to the statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each category of cash flow activity. Changes to the balance sheets include changing certain captions to conform to the presentation of Southern Company. Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to real estate and fleet vehicles where the Company is the lessee and to natural gas home appliances where the Company is the lessor. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note 5 for the disclosure impacted by ASU 2016-09. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. The Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. Affiliate Transactions SCS, as agent for Alabama Power, Georgia Power, and Southern Power, and the Company have long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and the Company by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the successor year ended December 31, 2017 , transportation revenue under these agreements from SCS and the Company were $136 million and $32 million , respectively. For the successor period of September 1, 2016 through December 31, 2016, transportation revenue under these agreements from SCS and the Company were $32 million and $15 million , respectively. See Note 4 under "Equity Method Investments – SNG" for additional information regarding the Company's investment in SNG. The Company has an agreement with SCS under which the following services are currently being rendered to the Company as direct or allocated cost: accounting, finance and treasury, tax, information technology, auditing, insurance and pension administration, human resources, systems and procedures, purchasing, and other services. For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 , costs for these services amounted to $63 million and $17 million , respectively. 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. SCS, as agent for Alabama Power, Georgia Power, and Southern Power, has agreements with certain subsidiaries of the Company to purchase natural gas. For the successor year ended December 31, 2017 , natural gas purchases made by SCS from the Company's subsidiaries were $142 million . For the successor period of July 1, 2016 through December 31, 2016 , natural gas purchases made by SCS from the Company's subsidiaries were $27 million . Regulatory Assets and Liabilities The Company is subject to accounting requirements 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: 2017 2016 Note (in millions) Environmental remediation $ 410 $ 411 (a,b) Retiree benefit plans 270 325 (a,c) Long-term debt fair value adjustment 138 154 (d) Under recovered regulatory clause revenues 98 118 (e) Other regulatory assets 79 58 (f) Other cost of removal obligations (1,646 ) (1,616 ) (g) Deferred income tax credits (1,063 ) (22 ) (g,i) Over recovered regulatory clause revenues (144 ) (104 ) (e) Other regulatory liabilities (21 ) (39 ) (h) Total regulatory assets (liabilities), net $ (1,879 ) $ (715 ) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Not earning a return as offset in rate base by a corresponding asset or liability. (b) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (c) Recovered and amortized over the average remaining service period which range up to 15 years . See Note 2 for additional information. (d) Recovered over the remaining life of the original debt issuances, which range up to 21 years . (e) Recorded and recovered or amortized as approved or accepted by the appropriate state regulatory agencies over periods generally not exceeding eight years . (f) Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, deferred depreciation expense, and financial instrument-hedging assets, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding 10 years , except for financial hedging-instruments. Financial instrument-hedging assets 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, and actual income earned is refunded through the energy cost recovery clause. (g) Other cost of removal obligations are recorded and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years . Cost of removal liabilities will be settled and trued up following completion of the related activities. (h) Comprised of several components including energy efficiency programs, unamortized bond issuance costs and financial instrument-hedging liabilities which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding a range of four years to 20 years , except for financial hedging-instruments. Financial instrument-hedging 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, and actual income earned is refunded through the energy cost recovery clause. (i) Includes excess deferred income tax liabilities not subject to normalization as a result of the Tax Reform Legislation, the recovery and amortization of which will be determined by the applicable state regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional details. In the event that a portion of a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the natural gas distribution utility 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 "Regulatory Matters" for additional information. Revenues Gas Distribution Operations The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the Company's utilities. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. All of the natural gas distribution utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period. The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, so long as the amounts recognized will be collected from customers within 24 months of recognition. These programs are as follows: • Weather normalization adjustments – reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas, Elizabethtown Gas, and Chattanooga Gas; • Revenue normalization mechanisms – mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas, Chattanooga Gas, and Elkton Gas; and • Revenue true-up adjustment – included within the provisions of the Georgia Rate Adjustment Mechanism (GRAM) program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a monthly positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year. Revenue Taxes The Company charges customers for gas revenue and gas use taxes imposed on the Company and remits amounts owed to various governmental authorities. Gas revenue taxes are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on the Company are recorded as operating expenses on the statements of income. Gas use taxes are excluded from revenue and expense with the related administrative fee included in operating revenues when the tax is imposed on the customer. Revenue taxes included in operating expenses were $98 million and $31 million for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 , respectively, and $56 million and $101 million for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , respectively. Gas Marketing Services The Company recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. The Company also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period. The Company recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. Revenues for warranty and repair contracts are recognized on a straight-line basis over the contract term while revenues for maintenance services are recognized at the time such services are performed. Wholesale Gas Services The Company nets revenues from energy and risk management activities with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. The Company records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue. Concentration of Revenue 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. Cost of Natural Gas and Other Sales Gas Distribution Operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the Company charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively. Gas Marketing Services The Company's gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, the Company also includes costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives. The Company records the costs to service its warranty and repair contract claims as cost of other sales. 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 on the balance sheet, excluding revenue taxes which are presented on the statements of income. See "Revenues – Gas Distribution Operations – Revenue Taxes" herein for additional information. 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, or fair value at the effective date of the Merger as appropriate, 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: 2017 2016 (in millions) Utility plant in service $ 13,079 $ 11,996 Information technology equipment and software 366 324 Storage facilities 1,599 1,463 Other 789 725 Total other plant in service 2,754 2,512 Total plant in service $ 15,833 $ 14,508 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. The portion of non-working gas used to maintain the structural integrity of the Company's natural gas storage facilities that is considered to be non-recoverable is recorded as depreciable property, plant, and equipment, while the recoverable or retained portion is recorded as non-depreciable property, plant, and equipment. The amount of non-cash property additions recognized for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $135 million , $63 million , $41 million , and $48 million , respectively. These amounts are comprised of construction-related accounts payable outstanding at the end of each period. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.9% in 2017 , 2.8% in 2016 , and 2.7% in 2015 . Depreciation studies are conducted periodically to update the composite rates that are approved by the respective state regulatory agency. 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 asset are retired when the related property unit is retired. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over the following useful lives: five to 15 years for transportation equipment, 40 to 60 years for storage facilities, and up to 65 years for other assets. Allowance for Funds Used During Construction The Company records AFUDC for Atlanta Gas Light, Nicor Gas, Chattanooga Gas, and Elizabethtown Gas, 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, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The capital expenditures of the other three natural gas utilities do not qualify for AFUDC treatment. The Company's AFUDC composite rates are as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Atlanta Gas Light 8.10 % 4.05 % 4.05 % 8.10 % Chattanooga Gas 7.41 3.71 3.71 7.41 Elizabethtown Gas (*) 1.56 0.84 0.84 1.69 Nicor Gas (*) 1.22 1.50 1.50 0.82 (*) Variable rate is determined by the FERC method of AFUDC accounting. Cash payments for interest during the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 totaled $223 million , $135 million , $119 million , and $181 million , respectively. Impairment of Long-Lived Assets 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 ass |
Retirement Benefits
Retirement Benefits | 12 Months Ended |
Dec. 31, 2017 | |
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, with the exception of employees at Southern Company Gas and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018 . 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 electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2018 , no other postretirement trust contributions are expected. In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. This qualified pension plan is funded in accordance with requirements of ERISA. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2018 . Southern Company Gas also provides certain non-qualified defined benefit and defined contribution 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 Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018 , no other postretirement trust contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.40 % 4.58 % 4.17 % Discount rate – interest costs 3.77 3.88 4.17 Discount rate – service costs 4.81 4.98 4.48 Expected long-term return on plan assets 7.92 8.16 8.20 Annual salary increase 4.37 4.37 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.23 % 4.38 % 4.04 % Discount rate – interest costs 3.54 3.66 4.04 Discount rate – service costs 4.64 4.85 4.39 Expected long-term return on plan assets 6.84 6.66 6.97 Annual salary increase 4.37 4.37 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.80 % 4.40 % Annual salary increase 4.32 4.37 Other postretirement benefit plans Discount rate 3.68 % 4.23 % Annual salary increase 4.32 4.37 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 eight 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. 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 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, 2017 as follows: 1 Percent 1 Percent (in millions) Benefit obligation $ 132 $ 113 Service and interest costs 4 3 Pension Plans The total accumulated benefit obligation for the pension plans was $12.6 billion at December 31, 2017 and $11.3 billion at December 31, 2016 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 12,385 $ 10,542 Acquisitions — 1,244 Service cost 293 262 Interest cost 455 422 Benefits paid (596 ) (466 ) Plan amendments (26 ) 39 Actuarial (gain) loss 1,297 342 Balance at end of year 13,808 12,385 Change in plan assets Fair value of plan assets at beginning of year 11,583 9,234 Acquisitions — 837 Actual return (loss) on plan assets 1,953 902 Employer contributions 52 1,076 Benefits paid (596 ) (466 ) Fair value of plan assets at end of year 12,992 11,583 Accrued liability $ (816 ) $ (802 ) At December 31, 2017 , the projected benefit obligations for the qualified and non-qualified pension plans were $13.2 billion and $652 million , respectively. All pension plan assets are related to the qualified pension plans. Amounts presented in the following tables exclude regulatory assets of $334 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016. Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 3,273 $ 3,207 Other current liabilities (53 ) (53 ) Employee benefit obligations (763 ) (749 ) Other regulatory liabilities, deferred (118 ) (87 ) Accumulated OCI 107 100 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 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 2018 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ 3 $ 104 Regulatory assets 14 3,140 Total $ 17 $ 3,244 Balance at December 31, 2016: Accumulated OCI $ 4 $ 96 Regulatory assets 51 3,069 Total $ 55 $ 3,165 Estimated amortization in net periodic pension cost in 2018: Accumulated OCI $ 1 $ 9 Regulatory assets 4 204 Total $ 5 $ 213 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, 2017 and 2016 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2015 $ 125 $ 2,998 Net (gain) loss (20 ) 243 Change in prior service costs 2 37 Reclassification adjustments: Amortization of prior service costs (1 ) (13 ) Amortization of net gain (loss) (6 ) (145 ) Total reclassification adjustments (7 ) (158 ) Total change (25 ) 122 Balance at December 31, 2016 $ 100 $ 3,120 Net (gain) loss 15 227 Change in prior service costs — (26 ) Reclassification adjustments: Amortization of prior service costs (1 ) (11 ) Amortization of net gain (loss) (7 ) (155 ) Total reclassification adjustments (8 ) (166 ) Total change 7 35 Balance at December 31, 2017 $ 107 $ 3,155 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 293 $ 262 $ 257 Interest cost 455 422 445 Expected return on plan assets (897 ) (782 ) (724 ) Recognized net (gain) loss 162 150 215 Net amortization 12 14 25 Net periodic pension cost $ 25 $ 66 $ 218 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, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 634 2019 637 2020 663 2021 681 2022 704 2023 to 2027 3,836 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,297 $ 1,989 Acquisitions — 338 Service cost 24 22 Interest cost 79 76 Benefits paid (136 ) (119 ) Actuarial (gain) loss 65 (16 ) Plan amendments 3 — Retiree drug subsidy 7 7 Balance at end of year 2,339 2,297 Change in plan assets Fair value of plan assets at beginning of year 944 833 Acquisitions — 100 Actual return (loss) on plan assets 154 58 Employer contributions 84 65 Benefits paid (129 ) (112 ) Fair value of plan assets at end of year 1,053 944 Accrued liability $ (1,286 ) $ (1,353 ) Amounts presented in the following tables exclude regulatory assets of $77 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016. Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 382 $ 419 Other current liabilities (5 ) (4 ) Employee benefit obligations (1,281 ) (1,349 ) Other regulatory liabilities, deferred (41 ) (41 ) Accumulated OCI 4 7 Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2017 and 2016 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 2018 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ — $ 4 Net regulatory assets 21 320 Total $ 21 $ 324 Balance at December 31, 2016: Accumulated OCI $ — $ 7 Net regulatory assets 25 353 Total $ 25 $ 360 Estimated amortization as net periodic postretirement benefit cost in 2018: Net regulatory assets $ 7 $ 14 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, 2017 and 2016 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2015 $ 8 $ 411 Net (gain) loss (1 ) (13 ) Reclassification adjustments: Amortization of prior service costs — (6 ) Amortization of net gain (loss) — (14 ) Total reclassification adjustments — (20 ) Total change (1 ) (33 ) Balance at December 31, 2016 $ 7 $ 378 Net (gain) loss (3 ) (21 ) Change in prior service costs — 3 Reclassification adjustments: Amortization of prior service costs — (6 ) Amortization of net gain (loss) — (13 ) Total reclassification adjustments — (19 ) Total change (3 ) (37 ) Balance at December 31, 2017 $ 4 $ 341 Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 24 $ 22 $ 23 Interest cost 79 76 78 Expected return on plan assets (66 ) (60 ) (58 ) Net amortization 20 21 21 Net periodic postretirement benefit cost $ 57 $ 59 $ 64 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 Payments Subsidy Receipts Total (in millions) 2018 $ 144 $ (7 ) $ 137 2019 148 (8 ) 140 2020 151 (8 ) 143 2021 154 (9 ) 145 2022 156 (9 ) 147 2023 to 2027 780 (48 ) 732 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 plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The investment strategy for plan assets related to the Company's qualified pension plans 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 plans 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 Southern Company plan 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. Investment Strategies and Benefit Plan Asset Fair Values A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below: Description Valuation Methodology ● 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. Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. ● Fixed income: A mix of domestic and international bonds. 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. ● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. ● 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 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. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values, and actual allocations relative to the target allocations, of Southern Company's pension plan (excluding Southern Company Gas) as of December 31, 2017 and 2016 are presented below. 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. These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 2,405 $ 1,159 $ — $ — $ 3,564 26 % 31 % International equity (*) 1,555 1,403 — — 2,958 25 25 Fixed income: 23 24 U.S. Treasury, government, and agency bonds — 841 — — 841 Mortgage- and asset-backed securities — 8 — — 8 Corporate bonds — 1,201 — — 1,201 Pooled funds — 650 — — 650 Cash equivalents and other 217 11 — — 228 Real estate investments 469 — — 1,188 1,657 14 13 Special situations — — — 180 180 3 1 Private equity — — — 669 669 9 6 Total $ 4,646 $ 5,273 $ — $ 2,037 $ 11,956 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 2,010 $ 927 $ — $ — $ 2,937 26 % 29 % International equity (*) 1,231 1,110 — — 2,341 25 22 Fixed income: 23 29 U.S. Treasury, government, and agency bonds — 588 — — 588 Mortgage- and asset-backed securities — 13 — — 13 Corporate bonds — 991 — — 991 Pooled funds — 524 — — 524 Cash equivalents and other 996 2 — — 998 Real estate investments 310 — — 1,152 1,462 14 13 Special situations — — 180 180 3 2 Private equity — — — 549 549 9 5 Total $ 4,547 $ 4,155 $ — $ 1,881 $ 10,583 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2017 and 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets 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 Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 155 $ 323 $ — $ — $ 478 International equity (*) — 166 — — 166 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 39 — — 39 Cash equivalents and other 84 25 — 48 157 Real estate investments 3 — — 16 19 Private equity — — — 1 1 Total $ 242 $ 638 $ — $ 65 $ 945 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016 , along with the targets, is presented below: Target 2017 2016 Pension plan assets: Equity 53 % 65 % 69 % Fixed Income 15 19 20 Cash 2 6 1 Other 30 10 10 Balance at end of period 100 % 100 % 100 % The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Total Target Allocation Actual Allocation As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 132 $ 35 $ — $ — $ 167 37 % 40 % International equity (*) 47 76 — — 123 23 23 Fixed income: 30 29 U.S. Treasury, government, and agency bonds — 32 — — 32 Corporate bonds — 37 — — 37 Pooled funds — 55 — — 55 Cash equivalents and other 10 — — — 10 Trust-owned life insurance — 426 — — 426 Real estate investments 16 — — 36 52 5 5 Special situations — — — 5 5 1 1 Private equity — — — 20 20 4 2 Total $ 205 $ 661 $ — $ 61 $ 927 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 118 $ 28 $ — $ — $ 146 39 % 40 % International equity (*) 37 61 — — 98 23 21 Fixed income: 29 31 U.S. Treasury, government, and agency bonds — 24 — — 24 Corporate bonds — 30 — — 30 Pooled funds — 49 — — 49 Cash equivalents and other 41 — — — 41 Trust-owned life insurance — 382 — — 382 Real estate investments 11 — — 35 46 5 5 Special situations — — — 5 5 1 1 Private equity — — — 17 17 3 2 Total $ 207 $ 574 $ — $ 57 $ 838 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of Southern Company Gas' other postretirement benefit plan assets for the period ended December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets 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 Net Asset Value as a Practical Expedient Total As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 3 $ 69 $ — $ — $ 72 International equity (*) — 22 — — 22 Fixed income: Pooled funds — 24 — — 24 Cash equivalents and other 2 — — 1 3 Total $ 5 $ 115 $ — $ 1 $ 121 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient Total As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016 , along with the targets, is presented below: Target 2017 2016 Other postretirement benefit plan assets: Equity 72 % 76 % 74 % Fixed Income 24 20 23 Cash 1 2 1 Other 3 2 2 Total 100 % 100 % 100 % Employee Savings Plan Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2017 , 2016 , and 2015 were $118 million , $105 million , and $92 million , respectively. |
ALABAMA POWER CO | |
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 to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018 . 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, 2018 , no other postretirement trusts contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.44 % 4.67 % 4.18 % Discount rate – interest costs 3.76 3.90 4.18 Discount rate – service costs 4.85 5.07 4.49 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.27 % 4.51 % 4.04 % Discount rate – interest costs 3.58 3.69 4.04 Discount rate – service costs 4.70 4.96 4.40 Expected long-term return on plan assets 6.83 6.83 7.17 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.81 % 4.44 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.71 % 4.27 % Annual salary increase 4.46 4.46 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 eight 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. 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 30 $ 26 Service and interest costs 1 1 Pension Plans The total accumulated benefit obligation for the pension plans was $2.7 billion at December 31, 2017 and $2.4 billion at December 31, 2016 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,663 $ 2,506 Service cost 63 57 Interest cost 98 95 Benefits paid (120 ) (109 ) Actuarial (gain) loss 294 114 Balance at end of year 2,998 2,663 Change in plan assets Fair value of plan assets at beginning of year 2,517 2,279 Actual return (loss) on plan assets 427 206 Employer contributions 12 141 Benefits paid (120 ) (109 ) Fair value of plan assets at end of year 2,836 2,517 Accrued liability $ (162 ) $ (146 ) At December 31, 2017 , the projected benefit obligations for the qualified and non-qualified pension plans were $2.9 billion and $126 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 890 $ 870 Other current liabilities (12 ) (12 ) Employee benefit obligations (150 ) (134 ) Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 8 $ 10 $ 1 Net (gain) loss 882 860 54 Regulatory assets $ 890 $ 870 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 870 $ 822 Net (gain) loss 64 84 Change in prior service costs — 7 Reclassification adjustments: Amortization of prior service costs (2 ) (3 ) Amortization of net gain (loss) (42 ) (40 ) Total reclassification adjustments (44 ) (43 ) Total change 20 48 Ending balance $ 890 $ 870 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 63 $ 57 $ 59 Interest cost 98 95 106 Expected return on plan assets (196 ) (184 ) (178 ) Recognized net (gain) loss 42 40 55 Net amortization 2 3 6 Net periodic pension cost $ 9 $ 11 $ 48 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, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 129 2019 134 2020 139 2021 143 2022 148 2023 to 2027 807 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 501 $ 505 Service cost 6 5 Interest cost 17 18 Benefits paid (29 ) (28 ) Actuarial (gain) loss 20 (1 ) Retiree drug subsidy 2 2 Balance at end of year 517 501 Change in plan assets Fair value of plan assets at beginning of year 367 363 Actual return (loss) on plan assets 60 23 Employer contributions 6 7 Benefits paid (27 ) (26 ) Fair value of plan assets at end of year 406 367 Accrued liability $ (111 ) $ (134 ) Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 63 $ 86 Other regulatory liabilities, deferred (7 ) (10 ) Employee benefit obligations (111 ) (134 ) Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 11 $ 15 $ 4 Net (gain) loss 45 61 1 Net regulatory assets $ 56 $ 76 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Net regulatory assets (liabilities): Beginning balance $ 76 $ 82 Net (gain) loss (15 ) — Reclassification adjustments: Amortization of prior service costs (4 ) (4 ) Amortization of net gain (loss) (1 ) (2 ) Total reclassification adjustments (5 ) (6 ) Total change (20 ) (6 ) Ending balance $ 56 $ 76 Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 6 $ 5 $ 6 Interest cost 17 18 20 Expected return on plan assets (25 ) (25 ) (26 ) Net amortization 5 6 5 Net periodic postretirement benefit cost $ 3 $ 4 $ 5 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 Payments Subsidy Receipts Total (in millions) 2018 $ 31 $ (2 ) $ 29 2019 32 (2 ) 30 2020 33 (3 ) 30 2021 34 (3 ) 31 2022 35 (3 ) 32 2023 to 2027 173 (14 ) 159 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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 42 % 44 % 44 % International equity 22 22 20 Domestic fixed income 28 28 29 Special situations 1 — 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. 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, 2017 and 2016 . 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, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 572 $ 276 $ — $ — $ 848 International equity (*) 370 333 — — 703 Fixed income: U.S. Treasury, government, and agency bonds — 200 — — 200 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 286 — — 286 Pooled funds — 155 — — 155 Cash equivalents and other 51 3 — — 54 Real estate investments 111 — — 283 394 Special situations — — — 43 43 Private equity — — — 159 159 Total $ 1,104 $ 1,255 $ — $ 485 $ 2,844 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 477 $ 220 $ — $ — $ 697 International equity (*) 292 264 — — 556 Fixed income: U.S. Treasury, government, and agency bonds — 140 — — 140 Mortgage- and asset-backed securities — 3 — — 3 Corporate bonds — 235 — — 235 Pooled funds — 124 — — 124 Cash equivalents and other 236 1 — — 237 Real estate investments 74 — — 274 348 Special situations — — — 43 43 Private equity — — — 130 130 Total $ 1,079 $ 987 $ — $ 447 $ 2,513 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 52 $ 12 $ — $ — $ 64 International equity (*) 16 14 — — 30 Fixed income: U.S. Treasury, government, and agency bonds — 11 — — 11 Corporate bonds — 12 — — 12 Pooled funds — 7 — — 7 Cash equivalents and other 2 — — — 2 Trust-owned life insurance — 253 — — 253 Real estate investments 5 — — 12 17 Special situations — — — 2 2 Private equity — — — 7 7 Total $ 75 $ 309 $ — $ 21 $ 405 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 51 $ 10 $ — $ — $ 61 International equity (*) 13 12 — — 25 Fixed income: U.S. Treasury, government, and agency bonds — 7 — — 7 Corporate bonds — 10 — — 10 Pooled funds — 5 — — 5 Cash equivalents and other 14 — — — 14 Trust-owned life insurance — 220 — — 220 Real estate investments 4 — — 12 16 Special situations — — — 2 2 Private equity — — — 6 6 Total $ 82 $ 264 $ — $ 20 $ 366 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017 , 2016 , and 2015 were $23 million , $23 million , and $22 million , respectively. |
GEORGIA POWER CO | |
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 to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018 . 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, 2018 , no other postretirement trust contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.40 % 4.65 % 4.18 % Discount rate – interest costs 3.72 3.86 4.18 Discount rate – service costs 4.83 5.03 4.49 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.23 % 4.49 % 4.03 % Discount rate – interest costs 3.55 3.67 4.03 Discount rate – service costs 4.63 4.88 4.39 Expected long-term return on plan assets 6.79 6.27 6.48 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.79 % 4.40 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.68 % 4.23 % Annual salary increase 4.46 4.46 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 eight 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. 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 59 $ 50 Service and interest costs 2 2 Pension Plans The total accumulated benefit obligation for the pension plans was $3.8 billion at December 31, 2017 and $3.5 billion at December 31, 2016 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 3,800 $ 3,615 Service cost 74 70 Interest cost 138 136 Benefits paid (187 ) (164 ) Actuarial (gain) loss 363 143 Balance at end of year 4,188 3,800 Change in plan assets Fair value of plan assets at beginning of year 3,621 3,196 Actual return (loss) on plan assets 610 288 Employer contributions 14 301 Benefits paid (187 ) (164 ) Fair value of plan assets at end of year 4,058 3,621 Accrued liability $ (130 ) $ (179 ) At December 31, 2017 , the projected benefit obligations for the qualified and non-qualified pension plans were $4.0 billion and $153 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Prepaid pension costs $ 23 $ — Other regulatory assets, deferred 1,105 1,129 Other current liabilities (15 ) (14 ) Employee benefit obligations (138 ) (165 ) Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 14 $ 17 $ 2 Net (gain) loss 1,091 1,112 69 Regulatory assets $ 1,105 $ 1,129 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 1,129 $ 1,076 Net (gain) loss 36 99 Change in prior service costs — 14 Reclassification adjustments: Amortization of prior service costs (3 ) (5 ) Amortization of net gain (loss) (57 ) (55 ) Total reclassification adjustments (60 ) (60 ) Total change (24 ) 53 Ending balance $ 1,105 $ 1,129 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 74 $ 70 $ 73 Interest cost 138 136 154 Expected return on plan assets (283 ) (258 ) (251 ) Recognized net (gain) loss 57 55 76 Net amortization 3 5 9 Net periodic pension cost $ (11 ) $ 8 $ 61 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, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 196 2019 201 2020 207 2021 210 2022 216 2023 to 2027 1,156 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 847 $ 854 Service cost 7 6 Interest cost 29 30 Benefits paid (51 ) (45 ) Actuarial (gain) loss 28 (1 ) Retiree drug subsidy 3 3 Balance at end of year 863 847 Change in plan assets Fair value of plan assets at beginning of year 354 358 Actual return (loss) on plan assets 54 21 Employer contributions 26 17 Benefits paid (48 ) (42 ) Fair value of plan assets at end of year 386 354 Accrued liability $ (477 ) $ (493 ) Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 202 $ 213 Employee benefit obligations (477 ) (493 ) Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 5 $ 6 $ 1 Net (gain) loss 197 207 9 Regulatory assets $ 202 $ 213 The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 213 $ 223 Net (gain) loss (2 ) — Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (8 ) (9 ) Total reclassification adjustments (9 ) (10 ) Total change (11 ) (10 ) Ending balance $ 202 $ 213 Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 7 $ 6 $ 7 Interest cost 29 30 34 Expected return on plan assets (25 ) (22 ) (24 ) Net amortization 9 10 11 Net periodic postretirement benefit cost $ 20 $ 24 $ 28 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 Payments Subsidy Receipts Total (in millions) 2018 $ 55 $ (3 ) $ 52 2019 55 (3 ) 52 2020 56 (3 ) 53 2021 57 (4 ) 53 2022 58 (4 ) 54 2023 to 2027 288 (21 ) 267 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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 36 % 38 % 35 % International equity 24 24 24 Domestic fixed income 33 31 35 Special situations 1 1 1 Real estate investments 4 4 4 Private equity 2 2 1 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. 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, 2017 and 2016 . 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, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 819 $ 394 $ — $ — $ 1,213 International equity (*) 529 477 — — 1,006 Fixed income: U.S. Treasury, government, and agency bonds — 286 — — 286 Mortgage- and asset-backed securities — 3 — — 3 Corporate bonds — 409 — — 409 Pooled funds — 221 — — 221 Cash equivalents and other 74 4 — — 78 Real estate investments 160 — — 404 564 Special situations — — — 61 61 Private equity — — — 228 228 Total $ 1,582 $ 1,794 $ — $ 693 $ 4,069 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 686 $ 317 $ — $ — $ 1,003 International equity (*) 420 380 — — 800 Fixed income: U.S. Treasury, government, and agency bonds — 201 — — 201 Mortgage- and asset-backed securities — 4 — — 4 Corporate bonds — 338 — — 338 Pooled funds — 179 — — 179 Cash equivalents and other 340 1 — — 341 Real estate investments 106 — — 394 500 Special situations — — — 61 61 Private equity — — — 188 188 Total $ 1,552 $ 1,420 $ — $ 643 $ 3,615 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 53 $ 11 $ — $ — $ 64 International equity (*) 14 46 — — 60 Fixed income: U.S. Treasury, government, and agency bonds — 6 — — 6 Corporate bonds — 11 — — 11 Pooled funds — 41 — — 41 Cash equivalents and other 4 — — — 4 Trust-owned life insurance — 173 — — 173 Real estate investments 6 — — 11 17 Special situations — — — 2 2 Private equity — — — 6 6 Total $ 77 $ 288 $ — $ 19 $ 384 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 45 $ 9 $ — $ — $ 54 International equity (*) 11 37 — — 48 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Corporate bonds — 9 — — 9 Pooled funds — 38 — — 38 Cash equivalents and other 15 — — — 15 Trust-owned life insurance — 162 — — 162 Real estate investments 3 — — 11 14 Special situations — — — 2 2 Private equity — — — 5 5 Total $ 74 $ 260 $ — $ 18 $ 352 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017 , 2016 , and 2015 were $26 million , $27 million , and $26 million , respectively. |
GULF POWER CO | |
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 to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018 . 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, 2018 , no other postretirement trust contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.46 % 4.71 % 4.18 % Discount rate – interest costs 3.82 3.97 4.18 Discount rate – service costs 4.81 5.04 4.48 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.25 % 4.51 % 4.04 % Discount rate – interest costs 3.56 3.68 4.04 Discount rate – service costs 4.62 4.88 4.38 Expected long-term return on plan assets 7.81 8.05 8.07 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.82 % 4.46 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.69 % 4.25 % Annual salary increase 4.46 4.46 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 eight 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. 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 4 $ 3 Service and interest costs — — Pension Plans The total accumulated benefit obligation for the pension plans was $524 million at December 31, 2017 and $460 million at December 31, 2016 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 517 $ 480 Service cost 13 12 Interest cost 19 19 Benefits paid (20 ) (17 ) Actuarial (gain) loss 58 23 Balance at end of year 587 517 Change in plan assets Fair value of plan assets at beginning of year 491 420 Actual return (loss) on plan assets 81 39 Employer contributions 1 49 Benefits paid (20 ) (17 ) Fair value of plan assets at end of year 553 491 Accrued liability $ (34 ) $ (26 ) At December 31, 2017 , the projected benefit obligations for the qualified and non-qualified pension plans were $563 million and $25 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized on the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 160 $ 153 Other current liabilities (1 ) (1 ) Employee benefit obligations (33 ) (25 ) Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 2 $ 3 $ — Net (gain) loss 158 150 10 Regulatory assets $ 160 $ 153 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 153 $ 142 Net (gain) loss 15 16 Change in prior service costs — 2 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (7 ) (6 ) Total reclassification adjustments (8 ) (7 ) Total change 7 11 Ending balance $ 160 $ 153 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 13 $ 12 $ 12 Interest cost 19 19 20 Expected return on plan assets (38 ) (34 ) (32 ) Recognized net (gain) loss 7 6 9 Net amortization 1 1 1 Net periodic pension cost $ 2 $ 4 $ 10 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, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 22 2019 23 2020 25 2021 26 2022 28 2023 to 2027 155 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 83 $ 81 Service cost 1 1 Interest cost 3 3 Benefits paid (5 ) (4 ) Actuarial (gain) loss 1 2 Balance at end of year 83 83 Change in plan assets Fair value of plan assets at beginning of year 18 17 Actual return (loss) on plan assets 3 2 Employer contributions 4 3 Benefits paid (5 ) (4 ) Fair value of plan assets at end of year 20 18 Accrued liability $ (63 ) $ (65 ) Amounts recognized on the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 8 $ 11 Other current liabilities (1 ) (1 ) Other regulatory liabilities, deferred (2 ) (4 ) Employee benefit obligations (62 ) (64 ) Approximately $6 million and $7 million was included in net regulatory assets at December 31, 2017 and 2016 , respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is immaterial. The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Net regulatory assets (liabilities): Beginning balance $ 7 $ 5 Net (gain) loss (1 ) 2 Ending balance $ 6 $ 7 Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (1 ) (1 ) (1 ) Net periodic postretirement benefit cost $ 3 $ 3 $ 3 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 Payments Subsidy Receipts Total (in millions) 2018 $ 5 $ — $ 5 2019 5 — 5 2020 5 — 5 2021 6 (1 ) 5 2022 6 (1 ) 5 2023 to 2027 28 (2 ) 26 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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 25 % 30 % 28 % International equity 24 24 21 Domestic fixed income 25 26 31 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. 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, 2017 and 2016 . 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, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 112 $ 54 $ — $ — $ 166 International equity (*) 72 65 — — 137 Fixed income: U.S. Treasury, government, and agency bonds — 39 — — 39 Corporate bonds — 57 — — 57 Pooled funds — 30 — — 30 Cash equivalents and other 10 — — — 10 Real estate investments 22 — — 55 77 Special situations — — — 8 8 Private equity — — — 31 31 Total $ 216 $ 245 $ — $ 94 $ 555 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 93 $ 43 $ — $ — $ 136 International equity (*) 57 52 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 27 — — 27 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 47 — — 47 Pooled funds — 24 — — 24 Cash equivalents and other 46 — — — 46 Real estate investments 14 — — 53 67 Special situations — — — 8 8 Private equity — — — 25 25 Total $ 210 $ 194 $ — $ 86 $ 490 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 — — — 1 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 8 $ 8 $ — $ 3 $ 19 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 2 $ — $ — $ 5 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 8 $ 8 $ — $ 3 $ 19 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017 , 2016 , and 2015 were $5 million , $5 million , and $4 million , respectively. |
MISSISSIPPI POWER CO | |
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 to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018 . 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, 2018 , no other postretirement trust contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.44 % 4.69 % 4.17 % Discount rate – interest costs 3.81 3.97 4.17 Discount rate – service costs 4.83 5.04 4.49 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.22 % 4.47 % 4.03 % Discount rate – interest costs 3.55 3.66 4.03 Discount rate – service costs 4.65 4.88 4.38 Expected long-term return on plan assets 6.88 7.07 7.23 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.80 % 4.44 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.68 % 4.22 % Annual salary increase 4.46 4.46 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 eight 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. 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 5 $ 5 Service and interest costs — — Pension Plans The total accumulated benefit obligation for the pension plans was $541 million at December 31, 2017 and $479 million at December 31, 2016 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 534 $ 500 Service cost 15 13 Interest cost 20 19 Benefits paid (22 ) (20 ) Actuarial (gain) loss 55 22 Balance at end of year 602 534 Change in plan assets Fair value of plan assets at beginning of year 499 430 Actual return (loss) on plan assets 84 39 Employer contributions 2 50 Benefits paid (22 ) (20 ) Fair value of plan assets at end of year 563 499 Accrued liability $ (39 ) $ (35 ) At December 31, 2017 , the projected benefit obligations for the qualified and non-qualified pension plans were $571 million and $31 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 158 $ 154 Other current liabilities (3 ) (3 ) Employee benefit obligations (36 ) (32 ) Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 3 $ 3 $ — Net (gain) loss 155 151 10 Regulatory assets $ 158 $ 154 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 154 $ 144 Net (gain) loss 12 16 Change in prior service costs — 2 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (7 ) (7 ) Total reclassification adjustments (8 ) (8 ) Total change 4 10 Ending balance $ 158 $ 154 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 15 $ 13 $ 13 Interest cost 20 19 21 Expected return on plan assets (40 ) (35 ) (33 ) Recognized net (gain) loss 7 7 10 Net amortization 1 1 1 Net periodic pension cost $ 3 $ 5 $ 12 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, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 23 2019 24 2020 26 2021 27 2022 28 2023 to 2027 164 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 97 $ 97 Service cost 1 1 Interest cost 3 3 Benefits paid (6 ) (6 ) Actuarial (gain) loss 1 1 Retiree drug subsidy 1 1 Balance at end of year 97 97 Change in plan assets Fair value of plan assets at beginning of year 23 23 Actual return (loss) on plan assets 3 1 Employer contributions 4 4 Benefits paid (5 ) (5 ) Fair value of plan assets at end of year 25 23 Accrued liability $ (72 ) $ (74 ) Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 18 $ 21 Other regulatory liabilities, deferred (1 ) (2 ) Employee benefit obligations (72 ) (74 ) Approximately $17 million and $19 million was included in net regulatory assets at December 31, 2017 and 2016 , respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is $1 million . The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Net regulatory assets (liabilities): Beginning balance $ 19 $ 18 Net (gain) loss (1 ) 2 Reclassification adjustments: Amortization of net gain (loss) (1 ) (1 ) Total reclassification adjustments (1 ) (1 ) Total change (2 ) 1 Ending balance $ 17 $ 19 Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 4 Expected return on plan assets (1 ) (1 ) (2 ) Net amortization 1 1 1 Net periodic postretirement benefit cost $ 4 $ 4 $ 4 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 Payments Subsidy Receipts Total (in millions) 2018 $ 6 $ — $ 6 2019 6 — 6 2020 6 (1 ) 5 2021 7 (1 ) 6 2022 7 (1 ) 6 2023 to 2027 34 (2 ) 32 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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 21 % 25 % 23 % International equity 21 20 18 Domestic fixed income 37 38 43 Special situations 2 1 2 Real estate investments 12 11 10 Private equity 7 5 4 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. 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, 2017 and 2016 . 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, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 113 $ 55 $ — $ — $ 168 International equity (*) 73 66 — — 139 Fixed income: U.S. Treasury, government, and agency bonds — 40 — — 40 Corporate bonds — 56 — — 56 Pooled funds — 31 — — 31 Cash equivalents and other 10 1 — — 11 Real estate investments 22 — — 56 78 Special situations — — — 9 9 Private equity — — — 32 32 Total $ 218 $ 249 $ — $ 97 $ 564 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 95 $ 44 $ — $ — $ 139 International equity (*) 58 51 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 28 — — 28 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 46 — — 46 Pooled funds — 25 — — 25 Cash equivalents and other 47 — — — 47 Real estate investments 15 — — 54 69 Special situations — — — 8 8 Private equity — — — 26 26 Total $ 215 $ 195 $ — $ 88 $ 498 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 3 2 — — 5 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 — — — 1 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 9 $ 12 $ — $ 3 $ 24 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 9 $ 12 $ — $ 3 $ 24 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017 , 2016 , and 2015 were $5 million each year. |
SOUTHERN POWER CO | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS Effective in December 2017, 538 employees transferred from SCS to the Company. Accordingly, the Company assumed various compensation and benefit plans including a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). With the transfer of employees, the Company assumed the related benefit obligations from SCS of $139 million for the qualified pension plan (along with trust assets of $138 million ) and $11 million for other postretirement benefit plans, together with $36 million in prior service costs and net gains/losses that are in OCI. In 2018, the Company will also begin providing certain defined benefits under a non-qualified pension plan for a select group of management and highly compensated employees. No obligation related to these benefits was assumed in the employee transfer; however, obligations under the non-qualified pension plan for future services rendered by employees will be recognized beginning in 2018 and ultimately 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 that are to be funded on a cash basis. Prior to the transfer of employees in December 2017, substantially all expenses charged by SCS, including pension and other postretirement benefit costs, were recorded in other operations and maintenance expense. Beginning in 2018, in connection with the adoption of ASU 2017-07, the service cost component of pension and postretirement benefit costs will be recorded in other operations and maintenance expense while the non-service cost components of pension and postretirement benefit costs will be recorded in other income (expense). See Note 1 under "General" for additional information. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine the benefit obligations for the pension and other postretirement plans as of the December 31, 2017 measurement date are presented below. Assumptions used to determine benefit obligations: 2017 Pension plans Discount rate 3.94 % Annual salary increase 4.46 Other postretirement benefit plans Discount rate 3.81 % Annual salary increase 4.46 In determining the amount of pension cost to be recognized in 2018, the Company estimates the expected rate of return on pension plan assets using a financial model to project the expected return on the current investment portfolio. The analysis projects an expected rate of return on each of the different asset classes in order to arrive at the expected return on the entire portfolio relying on the 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), the trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of the trust's portfolio. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) is 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 An annual increase or decrease in the assumed medical care cost trend rate of 1% would have an immaterial effect on the APBO at December 31, 2017. Pension Plan The total accumulated benefit obligation for the pension plan was $111 million at December 31, 2017 . The projected benefit obligation for the pension plan was $139 million and the fair value of plan assets was $138 million at December 31, 2017 . Presented below are the amounts included in AOCI at December 31, 2017 related to the Company's pension plan that had not yet been recognized in net periodic pension cost, along with the estimated amortization of such amounts for 2018. 2017 Estimated Amortization in 2018 (in millions) Prior service cost $ 1 $ — Net (gain) loss 32 2 AOCI $ 33 Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plan. At December 31, 2017 , estimated benefit payments average approximately $4 million each year for the next five years, and for the five-year period from 2023 to 2027 estimated benefit payments are $27 million . Other Postretirement Benefits The APBO for the other postretirement benefit plan at December 31, 2017 is $11 million . Amounts recognized in the balance sheet at December 31, 2017 related to the Company's other postretirement benefit plan consist of the following: 2017 (in millions) Employee benefit obligations (included in other deferred credits and liabilities) $ (11 ) AOCI 3 Presented below are the amounts included in AOCI at December 31, 2017 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 2018. 2017 Estimated Amortization in 2018 (in millions) Net (gain) loss $ 3 $ — AOCI $ 3 Future benefit payments, which include any prescription drug benefits, and any offset from drug subsidiary receipts, are immaterial for each of the years 2018-2027. Benefit Plan Assets Pension 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 the pension plan 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 assets as of December 31, 2017 , along with the targeted mix of assets for the plan, is presented below: Target 2017 Pension plan assets: Domestic equity 26 % 31 % International equity 25 25 Fixed income 23 24 Special situations 3 1 Real estate investments 14 13 Private equity 9 6 Total 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension benefit plan 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 assets as of December 31, 2017 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension 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, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2017 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 28 $ 13 $ — $ — $ 41 International equity (*) 18 16 — — 34 Fixed income: U.S. Treasury, government, and agency bonds — 10 — — 10 Corporate bonds — 14 — — 14 Pooled funds — 8 — — 8 Cash equivalents and other 2 — — — 2 Real estate investments 5 — — 14 19 Special situations — — — 2 2 Private equity — — — 8 8 Total $ 53 $ 61 $ — $ 24 $ 138 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
SOUTHERN Co GAS | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS The Company has a qualified defined benefit, trusteed, pension plan covering most eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018 . The Company also provides certain non-qualified defined benefit and defined contribution 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 eligible retired employees through a postretirement benefit plan. The Company also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018 , no other postretirement trust contributions are expected. In connection with the Merger, the Company performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. This valuation resulted in increases to the projected benefit obligations for the pension and other postretirement benefit plans of approximately $177 million and $20 million , respectively, a decrease in the fair value of pension plan assets of $10 million , and an increase in the fair value of other postretirement benefit plan assets of $1 million . The Company also recorded a related regulatory asset of $437 million related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates for the natural gas distribution utilities. The previously unrecognized prior service cost and actuarial gain/loss related to non-utility subsidiaries were eliminated through purchase accounting adjustments. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for all periods presented and the benefit obligations as of the measurement date are presented below. Successor Predecessor Assumptions used to determine net periodic costs: Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Pension plans Discount rate – interest costs (a) 3.76 % 3.21 % 4.00 % 4.20 % Discount rate – service costs (a) 4.64 4.07 4.80 4.20 Expected long-term return on plan assets 7.60 7.75 7.80 7.80 Annual salary increase 3.50 3.50 3.70 3.70 Pension band increase (b) N/A 2.00 2.00 2.00 Other postretirement benefit plans Discount rate – interest costs (a) 3.40 % 2.84 % 3.60 % 4.00 % Discount rate – service costs (a) 4.55 3.96 4.70 4.00 Expected long-term return on plan assets 6.03 5.93 6.60 7.80 Annual salary increase 3.50 3.50 3.70 3.70 (a) Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate. (b) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates in accordance with the union agreements. Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.74 % 4.39 % Annual salary increase 2.88 3.50 Pension band increase (*) N/A 2.00 Other postretirement benefit plans Discount rate 3.62 % 4.15 % Annual salary increase 2.56 3.50 (*) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates in accordance with the union agreements. The Company estimates the expected return on pension plan and other postretirement benefit plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year's annual pension or other postretirement benefit plan cost; rather, this gain or loss reduces or increases future pension or other postretirement benefit plan costs. 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, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.40 % 4.50 % 2038 Post-65 medical 7.80 4.50 2038 Post-65 prescription 7.80 4.50 2038 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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 11 $ (10 ) Service and interest costs — — Pension Plans The total accumulated benefit obligation for the pension plans was $1.1 billion at December 31, 2017 and $1.1 billion at December 31, 2016 . Changes in the projected benefit obligations and the fair value of plan assets for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 1,133 $ 1,244 ` $ 1,067 Service cost 23 15 13 Interest cost 42 20 21 Plan amendments (26 ) — — Benefits paid (91 ) (31 ) (26 ) Actuarial (gain) loss 103 (115 ) 169 Balance at end of period 1,184 1,133 1,244 Change in plan assets Fair value of plan assets at beginning of period 983 837 ` 847 Actual return (loss) on plan assets 175 48 15 Employer contributions 1 129 1 Benefits paid (91 ) (31 ) (26 ) Fair value of plan assets at end of period 1,068 983 837 Accrued liability $ 116 $ 150 $ 407 At December 31, 2017 , the projected benefit obligations for the qualified and non-qualified pension plans were $1.1 billion and $44 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 217 $ 267 Other deferred charges and assets 85 58 Other current liabilities (3 ) (2 ) Employee benefit obligations (198 ) (206 ) Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 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 2018 . Regulatory Amortization Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ — $ — $ (42 ) Regulatory assets (liabilities) 40 (20 ) 197 Total $ 40 $ (20 ) $ 155 Balance at December 31, 2016: Accumulated OCI $ — $ — $ (43 ) Regulatory assets (liabilities) — (2 ) 269 Total $ — $ (2 ) $ 226 Estimated amortization in net periodic cost in 2018: Regulatory assets (liabilities) $ 3 $ (2 ) $ 16 The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for all periods presented were as follows: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2015: $ 282 $ 88 Reclassification adjustments: Amortization of prior service costs 1 — Amortization of net loss (9 ) (4 ) Total reclassification adjustments (8 ) (4 ) Total change (8 ) (4 ) Predecessor – Balance at June 30, 2016: $ 274 $ 84 Successor – Balance at July 1, 2016: $ — $ 368 Net (gain) loss (43 ) (87 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (15 ) Total reclassification adjustments — (14 ) Total change (43 ) (101 ) Successor – Balance at December 31, 2016: $ (43 ) $ 267 Net (gain) loss 1 (31 ) Reclassification adjustments: Amortization of regulatory assets — (1 ) Amortization of net loss — (18 ) Total reclassification adjustments — (19 ) Total change 1 (50 ) Successor – Balance at December 31, 2017: $ (42 ) $ 217 Components of net periodic pension costs for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) Service cost $ 23 $ 15 $ 13 $ 28 Interest cost 42 20 21 45 Expected return on plan assets (70 ) (35 ) (33 ) (65 ) Amortization of regulatory assets 1 — — — Amortization: Prior service costs — (1 ) (1 ) (2 ) Net (gain)/loss 18 14 13 31 Net periodic pension cost $ 14 $ 13 $ 13 $ 37 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. 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, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 100 2019 77 2020 79 2021 79 2022 80 2023 to 2027 392 Other Postretirement Benefits Changes in the APBO and the fair value of plan assets for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 308 $ 338 $ 318 Service cost 2 1 1 Interest cost 10 5 5 Benefits paid (19 ) (11 ) (11 ) Actuarial (gain) loss 3 (26 ) 24 Plan amendments 3 — — Employee contributions 3 1 1 Balance at end of period 310 308 338 Change in plan assets Fair value of plan assets at beginning of period 105 100 99 Actual return (loss) on plan assets 20 4 1 Employee contributions 3 1 1 Employer contributions 17 11 10 Benefits paid (20 ) (11 ) (11 ) Fair value of plan assets at end of year 125 105 100 Accrued liability $ 185 $ 203 $ 238 Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 46 $ 52 Employee benefit obligations (185 ) (203 ) Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is immaterial. Regulatory Amortization Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ — $ — $ (3 ) Regulatory assets (liabilities) 6 (7 ) 47 Total $ 6 $ (7 ) $ 44 Balance at December 31, 2016: Accumulated OCI $ — $ — $ (3 ) Regulatory assets (liabilities) — (12 ) 64 Total $ — $ (12 ) $ 61 The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for all periods presented were as follows: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2015: $ 36 $ 30 Net (gain) loss — — Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss (1 ) (1 ) Total reclassification adjustments (1 ) — Total change (1 ) — Predecessor – Balance at June 30, 2016: $ 35 $ 30 Successor – Balance at July 1, 2016: $ — $ 77 Net (gain) loss (3 ) (23 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (3 ) Total reclassification adjustments — (2 ) Total change (3 ) (25 ) Successor – Balance at December 31, 2016: $ (3 ) $ 52 Net (gain) loss — (5 ) Reclassification adjustments: Amortization of prior service costs — 3 Amortization of net loss — (4 ) Total reclassification adjustments — (1 ) Total change — (6 ) Successor – Balance at December 31, 2017: $ (3 ) $ 46 Components of the other postretirement benefit plans' net periodic cost for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) Service cost $ 2 $ 1 $ 1 $ 2 Interest cost 10 5 5 13 Expected return on plan assets (7 ) (3 ) (3 ) (7 ) Amortization of regulatory assets — 2 — — Amortization: Prior service costs (3 ) — (1 ) (3 ) Net (gain)/loss 4 — 2 6 Net periodic postretirement benefit cost $ 6 $ 5 $ 4 $ 11 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. At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 20 2019 20 2020 21 2021 21 2022 22 2023 to 2027 105 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. 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, 2017 and 2016 , along with the targets for each plan, is presented below: Target 2017 2016 Pension plan assets: Equity 53 % 65 % 69 % Fixed Income 15 19 20 Cash 2 6 1 Other 30 10 10 Balance at end of period 100 % 100 % 100 % Other postretirement benefit plan assets: Equity 72 % 76 % 74 % Fixed Income 24 20 23 Cash 1 2 1 Other 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 for its pension plan assets. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk. Investment Strategies Detailed below is a description of the investment strategies for the successor period 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. The investment strategies for the predecessor periods followed a policy to preserve the plans' capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans' assets were managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification. In developing the allocation policy for the assets of the pension and other postretirement benefit plans, the Company examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, the risk and return trade-offs of alternative asset classes and asset mixes were evaluated given long-term historical relationships as well as prospective capital market returns. The Company also conducted asset-liability studies to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. Asset mix guidelines were developed by incorporating the results of these analyses with an assessment of the Company's risk posture, and taking into account industry practices. The Company periodically evaluated its investment strategy to ensure that plan assets were sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, the Company made changes to its targeted asset allocations and investment strategy. 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, 2017 and 2016 . 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 for the successor period, 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. Management believes the portfolio is well-diversified with no significant concentrations of risk. 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, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2017 and 2016 , special situations (absolute return and hedge funds) investment assets are presented in the table 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 Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 155 $ 323 $ — $ — $ 478 International equity (*) — 166 — — 166 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 39 — — 39 Cash equivalents and other 84 25 — 48 157 Real estate investments 3 — — 16 19 Private equity — — — 1 1 Total $ 242 $ 638 $ — $ 65 $ 945 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2017 and 2016 , special situations (absolute return and hedge funds) investment assets are presented in the table 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 Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 69 $ — $ — $ 72 International equity (*) — 22 — — 22 Fixed income: Pooled funds — 24 — — 24 Cash equivalents and other 2 — — 1 3 Total $ 5 $ 115 $ — $ 1 $ 121 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Employee Savings Plan SCS sponsors 401(k) defined contribution plans covering certain eligible Southern Company Gas employees. Through December 31, 2017, the 401(k) plans provided matching contributions of either 65% on up to 8% of an employee's eligible compensation, or a 100% matching contribution on up to 3% of an employee's eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee's eligible compensation. Total matching contributions made to the 401(k) plans for the successor periods ended December 31, 2017 and 2016 were $17 million and $8 million , respectively, and for the predecessor periods ended June 30, 2016 and December 31, 2015 were $10 million and $16 million , respectively. For employees not accruing a benefit under the pension plan, additional contributions made to the 401(k) plans for the successor period ended December 31, 2017 were $2 million , for the successor period ended December 31, 2016 were not material, and for the predecessor periods ended June 30, 2016 and December 31, 2015 were $2 million for each period. Effective January 1, 2018, the 401(k) plans were merged into the Southern Company Employee Savings Plan, which is a defined contribution plan covering substantially all employees of the Company. Under this plan, the Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017. On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above. On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above. Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time. 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 standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO 2 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. Environmental Matters Environmental Remediation The Southern Company system must comply with environmental laws and regulations governing 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 affected sites. The traditional electric operating companies and the natural gas distribution utilities conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. Georgia Power's environmental remediation liability as of December 31, 2017 and 2016 was $22 million and $17 million , respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million and $44 million as of December 31, 2017 and 2016 , respectively. These estimated costs primarily 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'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 Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income. Southern Company Gas' environmental remediation liability as of December 31, 2017 and 2016 was $388 million and $426 million , respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs. The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on Southern 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 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. In 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, Georgia Power recovered approximately $18 million , based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers. Also in 2015, Alabama Power recovered approximately $26 million , which was applied to reduce the cost of service for the benefit of customers. In 2014, Alabama Power and Georgia Power filed 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. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims 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, 2015 through December 31, 2017. 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, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries back for the benefit of customers in accordance with direction from their respective PSC and, therefore, 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. FERC Matters Market-Based Rate Authority The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015. In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order. The ultimate outcome of these matters cannot be determined at this time. Regulatory Matters Alabama Power Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and 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. Rate RSE 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 WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. At December 31, 2016, Alabama Power's retail return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below. Effective in January 2017, Rate RSE increased 4.48% , or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018. In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time. Rate CNP PPA Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, 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, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016 , Alabama Power had an under recovered Rate CNP PPA balance of $12 million and $142 million , respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million . As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years . Alabama Power's current depreciation study became effective January 1, 2017. Rate CNP Compliance Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, 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 will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years . Alabama Power's current depreciation study became effective January 1, 2017. On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016 , Alabama Power had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million , respectively. 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 Southern 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 accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years . Alabama Power's current depreciation study became effective January 1, 2017. On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC. At December 31, 2017 , Alabama Power's under recovered fuel costs totaled $25 million , which is included in other regulatory assets, current. At December 31, 2016, Alabama Power had an over recovered fuel balance of $76 million , which was included in other regulatory liabilities, current. 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. When the reserve balance falls below $50 million , a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million . 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. No such accruals were recorded or designated in any period presented. In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million . Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million . The NDR balance at December 31, 2017 was $38 million . 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. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. Alabama Power retired Plant Gorgas Units 6 and 7 ( 200 MWs) and Plant Barry Unit 3 ( 225 MWs) in 2015. Additionally, Alabama Power ceased using coal at Plant Barry Units 1 and 2 ( 250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, Alabama Power also ceased using coal at Plant Greene County Units 1 and 2 ( 300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively. In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements. Georgia Power Rate Plans Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60 / 40 basis with their respective customers; thereafter, all merger savings will be retained by customers. In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million ; (2) Environmental Compliance Cost Recovery tariff by approximately $75 million ; (3) Demand-Side Management tariffs by approximately $3 million ; and (4) Municipal Franchise Fee tariff by approximately $13 million , for a total increase in base revenues of approximately $140 million . There were no changes to these tariffs in 2017. 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. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00% , and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC. On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power 's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time. Integrated Resource Plan In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B ( 217 MWs) and Plant Kraft Unit 1 ( 17 MWs), as well as the decertification of the Intercession City unit ( 143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC. Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4. The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case. The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program. In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity. In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case. Fuel Cost Recovery Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $3 |
ALABAMA POWER CO | |
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 standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO 2 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 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 affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the estimated 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. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable. 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. In 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, the Company recovered approximately $26 million , which was applied to reduce the cost of service for the benefit of customers. In 2014, the Company filed a 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. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, the Company filed an additional lawsuit against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2015 through December 31, 2017. 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, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, the Company expects to credit any recovery back for the benefit of customers in accordance with direction from the Alabama PSC and, therefore, 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. FERC Matters The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015. In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order. The ultimate outcome of these matters cannot be determined at this time. Retail Regulatory Matters Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and 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. Rate RSE 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 WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below. Effective in January 2017, Rate RSE increased 4.48% , or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range. On December 1, 2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018. In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time. Rate CNP PPA The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, 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, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016, the Company had an under recovered Rate CNP PPA balance of $12 million and $142 million , respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million . As discussed herein under "Rate RSE," the Company utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years . The Company's current depreciation study became effective January 1, 2017. Rate CNP Compliance Rate CNP Compliance allows for the recovery of the Company's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, 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 will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years . The Company's current depreciation study became effective January 1, 2017. On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, the Company had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million , respectively. 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 accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years . The Company's current depreciation study became effective January 1, 2017. On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC. At December 31, 2017, the Company's under recovered fuel costs totaled $25 million , which is included in deferred under recovered regulatory clause revenues. At December 31, 2016, the Company had an over recovered fuel balance of $76 million , which was included in other regulatory liabilities, current. 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. When the reserve balance falls below $50 million , a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million . 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. No such accruals were recorded or designated in any period presented. In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million . The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million . The NDR balance at December 31, 2017 was $38 million . 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. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. The Company retired Plant Gorgas Units 6 and 7 ( 200 MWs) and Plant Barry Unit 3 ( 225 MWs) in 2015. Additionally, the Company ceased using coal at Plant Barry Units 1 and 2 ( 250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, the Company also ceased using coal at Plant Greene County Units 1 and 2 ( 300 MWs representing the Company's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively. In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on the Company's financial statements. |
GEORGIA POWER CO | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters In 2011, plaintiffs filed a putative class action against the Company in the Superior Court of Fulton County, Georgia alleging that the Company's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. The Company filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is expected in late 2018. The Company believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time. The Company is also 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 standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO 2 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 Environmental Remediation The Company must comply with environmental laws and regulations governing 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 affected sites. See Note 1 under "Environmental Remediation Recovery" for additional information. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable. The Company's environmental remediation liability as of December 31, 2017 and 2016 was $22 million and $17 million , respectively. The Company has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. The ultimate outcome of these matters 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. In 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, the Company recovered approximately $18 million , based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers. In 2014, the Company filed 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. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, the Company filed additional lawsuits against the U.S. government in the Court of Federal Claims 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, 2015 through December 31, 2017. 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, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, the Company expects to credit any recovery back for the benefit of customers in accordance with direction from the Georgia PSC and, therefore, no material impact on the Company's net income is expected. On-site dry spent fuel storage facilities are operational at Plant Vogtle Units 1 and 2 and Plant Hatch. Facilities can be expanded to accommodate spent fuel through the expected life of each plant. FERC Matters The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015. In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order. The ultimate outcome of these matters cannot be determined at this time. Retail Regulatory Matters Rate Plans Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and the Company will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, the Company and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60 / 40 basis with their respective customers; thereafter, all merger savings will be retained by customers. In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million ; (2) ECCR tariff by approximately $75 million ; (3) Demand-Side Management tariffs by approximately $3 million ; and (4) Municipal Franchise Fee tariff by approximately $13 million , for a total increase in base revenues of approximately $140 million . There were no changes to these tariffs in 2017. 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. In 2015, the Company's retail ROE was within the allowed retail ROE range. In 2016, the Company's retail ROE exceeded 12.00% , and the Company will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, the Company's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC. On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, the Company is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on the Company 's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time. Integrated Resource Plan In July 2016, the Georgia PSC approved the Company's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B ( 217 MWs) and Plant Kraft Unit 1 ( 17 MWs) , as well as the decertification of the Intercession City unit ( 143 MWs total capacity) . In August 2016, the Plant Mitchell and Plant Kraft units were retired and the Company sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC. Additionally, the Georgia PSC approved the Company's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4. The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in the Company's 2019 base rate case. The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by the Company was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program. In 2017, the Company filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. The Company also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity. In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved the Company's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future rate case. Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved the Company's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review the Company's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless the Company deems it necessary to file a fuel case at an earlier time. The Company continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million . The Company's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48 -month time horizon. The Company's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016 , the Company's over recovered fuel balance totaled $84 million and is included in over recovered fuel clause revenues, current. 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. Storm Damage Recovery The Company is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to the Company's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in the regulatory asset for storm damage totaled approximately $260 million . At December 31, 2017 , the total balance in the regulatory asset related to storm damage was $333 million . The rate of storm damage cost recovery is expected to be adjusted as part of the Company's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on the Company's financial statements. See Note 1 under "Storm Damage Recovery" for additional information regarding the Company's storm damage reserve. |
GULF POWER CO | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | Nuclear Construction Project Status In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, the Company filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved the Company's recommendation to continue construction. The Company expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. The Company's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ( $7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). The Company's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017 , which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion , of which $1.6 billion had been incurred through December 31, 2017 . Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy In 2008, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price 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. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. The Company, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017. On June 9, 2017, the Company and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which the Company's proportionate share was approximately $1.7 billion . The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Company, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Company, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and the Company and the other Vogtle Owners surrendered the Westinghouse Letters of Credit. Additionally, on June 9, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. Effective October 23, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between the Company and the DOE, the Company is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement. On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or the Company determines that any of the Company's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year . In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against the Company or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of the Company and/or Southern Nuclear as agent, except in cases of willful misconduct. Regulatory Matters In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion . In addition, 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 up to the certified capital cost of $4.418 billion . As of December 31, 2017, the Company had recovered approximately $1.6 billion of financing costs. On January 30, 2018, the Company filed to decrease the NCCR tariff by approximately $50 million , effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018. The Company is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and the Company. On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by the Company in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) the Company would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable the Company's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30% , effective January 1, 2020, and (c) from 8.30% to 5.30% , effective January 1, 2021 (provided that the ROE in no case will be less than the Company's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to the Company's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than the Company's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which the Company's seventeenth VCM report are based do not materialize, both the Company and the Georgia PSC reserve the right to reconsider the decision to continue construction. On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. The Company believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on the Company's results of operations, financial condition, and liquidity. The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of the Company's portion of the PTCs is approximately $500 million per unit. In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017 , including total construction capital costs incurred through that date of $4.4 billion . The Company expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017 . The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017 , or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds. The ultimate outcome of these matters cannot be determined at this time. Cost and Schedule The Company's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows: (in billions) Project capital cost forecast $ 7.3 Net investment as of December 31, 2017 (3.4 ) Remaining estimate to complete $ 3.9 Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds. The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion , of which $1.6 billion had been incurred through December 31, 2017 . As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost. 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 may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, 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 matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, 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. The ultimate outcome of these matters cannot be determined at this time. Other Matters As of December 31, 2017 , the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among the Company, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion , subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. The ultimate outcome of these matters cannot be determined at this time. 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 standards for air, water, land, and protection of natural resources has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO 2 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 Environmental Remediation The Company must comply with environmental laws and regulations governing 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 affected sites. 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 and reasonably estimable. At December 31, 2017 and 2016, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $52 million and $44 million , respectively, of which approximately $5 million and $4 million , respectively, is included in under recovered regulatory clause revenues and other current liabilities and approximately $47 million and $40 million , respectively, is included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs primarily 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, the final disposition of these matters is not expected to have a material impact on the Company's financial statements. FERC Matters The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015. In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order. The ultimate outcome of these matters cannot be determined at this time. 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 Cases In the 2013 Rate Case Settlement Agreement, the Florida PSC authorized the Company to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction was not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, the Company recognized reductions in depreciation of $8.4 million and $20.1 million , respectively. No net reduction in depreciation was recorded in 2016. In 2017, the Company recognized the remaining $34.0 million reduction in depreciation. On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among the Company and three intervenors with respect to the Company's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, the Company increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million . The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, the Company continued its authorized retail ROE midpoint ( 10.25% ) and range ( 9.25% to 11.25% ), is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. The Company also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 ( 357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of the Company's ownership of Plant Scherer Unit 3 ( 205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of the Company's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause. The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to the Company's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, the Company must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to the Company's base rates and $15.6 million to the Company's environmental cost recovery rates effective beginning the first calendar month following approval. The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through the Company's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and the Company will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through the Company's fuel cost recovery rate. If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase the Company's maximum equity ratio from 52.5% to 53.5% for regulatory purposes. The ultimate outcome of these matters cannot be determined at this time. Cost Recovery Clauses As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to the Company's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made. On October 25, 2017, the Florida PSC approved the Company's annual clause rate request for its fuel, purchased power capacity, envir |
MISSISSIPPI POWER CO | |
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 standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO 2 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 Environmental Remediation The Company must comply with environmental laws and regulations governing 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 affected sites. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through established regulatory mechanisms. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable. FERC Matters Municipal and Rural Associations Tariff The Company provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term cost-based, FERC regulated MRA tariff. In March 2016, the Company reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the operational Kemper County energy facility assets providing service to customers and other related costs, (ii) amortization of the Kemper County energy facility-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities and has been recorded as a charge to income. On September 18, 2017, the Company and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which the Company and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA accepted by the FERC on October 31, 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the option to decrease its use of the Company's generation services under the MRA tariff, subject to annual and cumulative caps and a one -year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in the Company's revenues is not expected to be significant through 2020. Fuel Cost Recovery The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At December 31, 2017 , over-recovered wholesale MRA fuel costs were immaterial and at December 31, 2016 were approximately $13 million , and is included in over-recovered regulatory clause liabilities, current in the balance sheet. Effective January 1, 2018, the wholesale MRA fuel rate increased $11 million annually. 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. Market-Based Rate Authority The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015. In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order. The ultimate outcome of these matters cannot be determined at this time. Cooperative Energy Power Supply Agreement In 2008, the Company entered into a 10 -year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to 86 MWs. On February 5, 2018, the Company and Cooperative Energy executed an amendment to extend the PSA through March 31, 2021, effective April 1, 2018, with increased total capacity of 286 MWs. Cooperative Energy also has a 10 -year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Company's transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS amended the terms of the NITSA on January 12, 2018 to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021. This NITSA amendment remains subject to acceptance by the FERC. The ultimate outcome of these matters cannot be determined at this time. 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 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. In 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. On January 26, 2018, the Mississippi PSC issued an order directing utilities to file within 30 days information regarding the impact on rates resulting from Tax Reform Legislation. The Company's Kemper County energy facility rates, approved on February 6, 2018, include the effects of Tax Reform Legislation. The Company's 2018 ECO, revised 2018 PEP, and 2018 SRR rate filings, all submitted in February 2018, include the effects of Tax Reform Legislation and are subject to approval by the Mississippi PSC. The ultimate outcome of these matters cannot be determined at this time. 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 a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing. In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the MPUS disputed 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. I n 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million . Unresolved matters related to the 2010 PEP lookback filing, which remain under review, also impact the 2012 PEP lookback filing. In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9% , or $15 million , annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase. In 2014, 2015, 2016, and 2017, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, the Company submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4% , or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review. On February 7, 2018, the Company revised its annual projected PEP filing for 2018 to reflect the impacts of Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55% . See Note 5 for additional information. The ultimate outcome of these matters cannot be determined at this time. Energy Efficiency In 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 extended by an order issued by the Mississippi PSC in July 2016, until the time the Mississippi PSC approves a comprehensive portfolio plan program. The ultimate outcome of this matter cannot be determined at this time. On July 6, 2017, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider 2017 compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017. On November 30, 2017, the Company submitted its Energy Efficiency Cost Rider 2018 compliance filing which included a small decrease in annual retail revenues. The ultimate outcome of this matter 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 were placed in service in 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In 2014, the Company entered into a settlement agreement with the Sierra Club under which, among other things, 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 (and the units were retired in July 2016). 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 (which occurred in April 2015) and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 ( 200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas (which occurred in June and July 2016, respectively). 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. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with Plant Watson and Plant Greene County, respectively, for amortization over five -year periods that began in July 2016 and July 2017, respectively. As a result, these decisions are not expected to have a material impact on the Company's financial statements. In August 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2016, which requested the maximum 2% annual increase in revenues, or approximately $18 million , primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing, along with related carrying costs. On May 4, 2017, the Mississippi PSC approved the Company's ECO plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $ 18 million , primarily related to the carryforward from the prior year. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing, along with related carrying costs. On February 14, 2018, the Company submitted its ECO plan filing for 2018, including the effects of Tax Reform Legislation, which requested the maximum 2% annual increase in revenues, or approximately $17 million , primarily related to the carryforward from the prior year. Approximately $13 million of related revenue requirements in excess of the 2% maximum, along with related carrying costs, remains deferred for inclusion in the 2019 filing. The ultimate outcome of this matter 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. On January 12, 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which resulted in an annual revenue increase of approximately $55 million . On November 15, 2017, the Company filed its annual rate adjustment under the retail fuel cost recovery clause, requesting an additional increase of $39 million annually, which the Mississippi PSC approved on January 16, 2018 effective February 2018 through January 2019. At December 31, 2017 , the amount of under-recovered retail fuel costs included in the balance sheet in customer accounts receivable was approximately $6 million compared to $37 million over recovered at December 31, 2016. 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 July 6, 2017, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85% , or $8 million in annual retail revenues, primarily due to increased assessments. System Restoration Rider In February 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual of $3 million annually. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed an increase in the property damage reserve accrual of $1 million . These filings were suspended by the Mississippi PSC for review. On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Storm damage repairs were approximately $9 million . A portion of these costs was charged to the retail property damage reserve and was addressed in the 2018 SRR rate filing. On February 1, 2018, the Company submitted its 2018 SRR rate filing, including the effects of Tax Reform Legislation, which proposed that the SRR rate remain at zero and the annual accrual for the property damage reserve be reduced to $2 million in 2018. The ultimate outcome of these matters cannot be determined at this time. See Note 1 under "Provision for Property Damage" for additional information. Storm Damage Cost Recovery In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order on January 24, 2017, the Company eliminated the applicable Storm Restoration Charge because the bond sinking fund managed by the Mississippi State Bond Commission is substantially funded. Kemper County Energy Facility Overview The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to 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 County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper County energy facility construction, the Company constructed approximately 61 miles of CO 2 pipeline infrastructure for the transport of captured CO 2 for use in enhanced oil recovery. Schedule and Cost Estimate In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility . The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion , net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO 2 pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). 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 County energy facility 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 County energy facility in service in August 2014. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO 2 , and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, the Company experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, the Company determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification. On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among the Company, the MPUS, and certain intervenors (Kemper Settlement Agreement). At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion , including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, the Company had recorded charges to income of $3.07 billion ( $1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ( $2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ( $206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket , as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and gasifier-related assets. Rate Recovery Kemper Settlement Agreement On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years , respectively. The revenue requirement also reflects a disallowance related to a portion of the Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ( $85 million net of accumulated depreciation of $7 million ) pre-tax ( $48 million after tax). Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, the Company made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) the Company to file a reserve margin plan with the Mississippi PSC by August 2018. As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million , respectively. As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges. 2015 Rate Case On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order r egarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million , based on the Company's actual average capital structure, with a maximum common equity percentage of 49.733% , a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, the Company began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring the Company to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers. Lignite Mine and CO 2 Pipeline Facilities The Company owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility 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 responsible for the mining operations 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. The Company expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, the Company provided 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 constructed the CO 2 pipeline for the planned transport of captured CO 2 for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO 2 . Denbury has the right to terminate the contract at any time because the Company did not place the Kemper IGCC in service by July 1, 2017. The ultimate outcome of these matters cannot be determined at this time. Litigation On April 26, 2016, a complaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees |
SOUTHERN POWER CO | |
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 standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO 2 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. During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time. FERC Matters The Company and certain of its generation subsidiaries are subject to regulation by the FERC. The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing and filed their response with the FERC in 2015. In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order. The ultimate outcome of these matters cannot be determined at this time. |
SOUTHERN Co GAS | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of the Company, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and the Company's motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on the Company's financial statements. The Company is assessing its alleged involvement in an incident that occurred in one of its service territories that resulted in several deaths, injuries, and property damage. One of the Company's utilities has been named as one of the defendants in several lawsuits related to this incident. The Company has insurance that provides full coverage of any financial exposure in excess of $11 million that is related to this incident. During the successor period ended December 31, 2016 and the predecessor period ended December 31, 2015 , the Company recorded reserves for substantially all of its potential exposure from these cases. The ultimate outcome of this matter cannot be determined at this time. The Company is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be determined 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 The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations impact future results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites. The natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. The Company is subject to environmental remediation liabilities associated with 46 former MGP sites in five different states. Accrued environmental remediation costs of $388 million and $426 million have been recorded in the balance sheets as of December 31, 2017 and 2016, respectively. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies, with the exception of one site representing $2 million of the accrued remediation costs. In 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleged violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the EPA sought a total civil penalty of $0.3 million . On January 26, 2017, the EPA notified Nicor Gas that it agreed to voluntarily dismiss its administrative complaint with prejudice and without payment of a civil penalty or other further obligation on the part of Nicor Gas. The Company's ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time. FERC Matters At December 31, 2017 , gas midstream operations was involved in two gas pipeline construction projects. These projects, along with the Company's existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval. On January 19, 2018, the PennEast Pipeline project received FERC approval. Additionally, on August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced. See Note 4 for additional information. Regulatory Matters Regulatory Infrastructure Programs The Company has infrastructure improvement programs at several of its utilities. Descriptions of these programs are as follows: Nicor Gas In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% , of base rate revenues. In 2014, the Illinois Commission approved the nine -year regulatory infrastructure program, Investing in Illinois, under which Nicor Gas implemented rates that became effective in March 2015. Investing in Illinois is subject to annual review by the Illinois Commission. In conjunction with the base rate case order issued by the Illinois Commission on January 31, 2018, Nicor Gas is recovering the portion of these program costs incurred prior to December 31, 2017 through base rates. See "Base Rate Cases" herein for additional information. Atlanta Gas Light Atlanta Gas Light's STRIDE program, which was initially approved by the Georgia PSC in 2009, is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), and the Integrated Vintage Plastic Replacement Program (i-VPR) and consists of infrastructure development, enhancement, and replacement programs that are used to update and expand distribution systems and LNG facilities, improve system reliability, and meet operational flexibility and growth. For 2017 and subsequent years, the recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM. The i-CGP program authorized Atlanta Gas Light to spend $91 million through 2017 on projects to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. This program ended in 2017 and was replaced with a tariff to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. The i-SRP program authorized $445 million of capital spending through 2017 for projects to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, improve its peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four -year extension of its i-SRP seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. The i-VPR program authorized Atlanta Gas Light to spend $275 million through 2017 to replace 756 miles of aging plastic pipe that was installed primarily in the mid-1960s to the early 1980s. Atlanta Gas Light has identified approximately 3,300 miles of vintage plastic mains in its system that should be considered for potential replacement. See "Base Rate Cases" herein for additional information. The orders for the STRIDE programs provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the programs net of any cost savings from the programs. The regulatory asset represents recoverable incurred costs related to the programs that will be collected in future rates charged to customers through the rate riders. The future expected costs to be recovered through rates related to allowed, but not incurred costs, are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the program. See "Unrecognized Ratemaking Amounts" herein for additional information. Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operations and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operations and maintenance costs in excess of those included in its current base rates, depreciation, and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under recovered balance resulting from the timing difference. Elizabethtown Gas Elizabethtown Gas' 2013 extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program allowed for infrastructure investment of $115 million over four years and was focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital of 6.65% . Effective July 1, 2017, investments under this program, which ended September 30, 2017, are being recovered through base rate revenues. See "Base Rate Cases" herein for additional information. In 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. During the first quarter 2018, Elizabethtown Gas withdrew this filing in response to a proposed rule by the New Jersey BPU to incentivize utilities to accelerate investment in infrastructure replacement programs that enhance reliability, resiliency, and/or safety of the distribution system. The ultimate outcome of this matter cannot be determined at this time. Virginia Natural Gas In 2012, the Virginia Commission approved the Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure replacement program, to be completed over a five -year period. This program included a maximum allowance for capital expenditures of $25 million per year, not to exceed $105 million in total. In March 2016, the Virginia Commission approved an extension to the SAVE program for Virginia Natural Gas to replace more than 200 miles of aging pipeline infrastructure and invest up to $30 million in 2016 and up to $35 million annually through 2021. The SAVE program is subject to annual review by the Virginia Commission. In conjunction with the base rate case order issued by the Virginia Commission on December 21, 2017, Virginia Natural Gas is recovering the portion of these program costs incurred prior to September 1, 2017 through base rates. See "Base Rate Cases" herein for additional information. Florida City Gas In 2015, the Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program, under which costs incurred for replacing aging pipes are recovered through a rate rider with annual adjustments and true-ups. Under the program, Florida City Gas is authorized to spend $105 million over a 10 -year period on infrastructure relocation and enhancement projects. PRP Settlement In 2015, Atlanta Gas Light received a final order from the Georgia PSC for a rate true-up of allowed unrecovered revenue through 2014 related to its PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million previously unrecovered program revenue. The remaining $34 million requested related primarily to previously unrecognized ratemaking amounts and did not have a material impact on the Company's financial statements. The Company also recognized $1 million of interest expense and $5 million in operations and maintenance expense related to the PRP on the Company's statements of income for the predecessor year ended December 31, 2015. See "Unrecognized Ratemaking Amounts" herein for additional information. As a result of the PRP settlement, Atlanta Gas Light began recovering incremental PRP surcharge amounts through three phased in increases in addition to its previously existing PRP surcharge amount, which was established to address recovery of the unrecovered PRP balance of $144 million in 2015 and the estimated amounts to be earned under the program through 2025. The initial incremental surcharge of approximately $15 million annually was effective in October 2015, with additional annual increases of approximately $15 million in each of October 2016 and 2017. The final increase scheduled for October 2017 was included in the implementation of GRAM in March 2017. The under recovered balance is the result of the continued revenue requirement earned under the program offset by the existing and incremental PRP surcharges. The unrecovered balance at December 31, 2017 was $187 million , including $104 million of unrecognized equity return. The PRP surcharge will remain in effect until the earlier of the full recovery of the under recovered amount or December 31, 2025. See "Base Rate Cases" herein for additional information on GRAM. One of the capital projects under the PRP experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. These mitigation costs will be included in future base rates in 2018. Provisions in the order resulted in the recognition of $5 million in operations and maintenance expense for the predecessor year ended December 31, 2015 on the Company's statements of income. In 2017, Atlanta Gas Light recovered $20 million from the settlement of contractor litigation claims and continues to pursue contractual and legal claims against a third-party contractor. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. The ultimate outcome of this matter cannot be determined at this time. Base Rate Cases Settled Base Rate Cases On February 21, 2017, the Georgia PSC approved GRAM and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, using an earnings band based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Atlanta Gas Light adjusts rates up to the lower end of the band of 10.55% and adjusts rates down to the higher end of the band of 10.95% . Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the i-VPR and i-SRP, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM. Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the i-CGP that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC. Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6% . Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the proposed sale of Elizabethtown Gas. On December 21, 2017, the Virginia Commission approved a settlement for a $34 million increase in annual base rate revenues, effective September 1, 2017, including $13 million related to the recovery of investments under the SAVE program. See "Regulatory Infrastructure Programs" herein for additional information. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates. On January 31, 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective February 8, 2018, based on a ROE of 9.8% . Pending Base Rate Cases On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. On January 29, 2018, Florida City Gas filed an update to incorporate the effects of the Tax Reform Legislation that, if approved, would reduce the requested base rate revenues by $4 million . The requested increase is based on a 2018 projected test year and a ROE of 11.25% . The requested increase includes $3 million related to the recovery of investments under SAFE that are currently being recovered through a surcharge. Additionally, Florida City Gas requested an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018. On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, annual base rate revenues will increase by $22 million , effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018. On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission requesting a $7 million increase in annual base rate revenues. The requested increase, which incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25% . The Tennessee Public Utility Commission is expected to rule on the requested increase in the third quarter 2018. The ultimate outcome of these pending base rate cases cannot be determined at this time. Other The New Jersey BPU, Virginia Commission, Tennessee Public Utility Commission, and Maryland PSC each issued an order effective January 1, 2018 that requires utilities in their respective states to track as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes. The New Jersey BPU's order requires Elizabethtown Gas to file by March 2, 2018 proposed revised base rates with an April 1, 2018 interim effective date and a July 1, 2018 final effective date. Virginia Natural Gas will address the Virginia Commission's order in its Annual Information Filing, which will be filed by July 1, 2018. The Tennessee Public Utility Commission's order required Chattanooga Gas to file proposals to reduce rates or make other ratemaking adjustments to account for the impact of the Tax Reform Legislation. Chattanooga Gas made the required filing as part of its February 15, 2018 general base rate case filing. The Maryland PSC's order required Elkton Gas to file an explanation of the impact of the Tax Reform Legislation on its expenses and revenues, as well as when and how it expects to pass through to its customers those effects. Elkton Gas made the required filing on February 15, 2018 and will reduce annual base rates by $0.1 million effective April 1, 2018. Credits will be issued to customers for the impact of the Tax Reform Legislation from January 2018 through March 2018. The Illinois Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018. The ultimate outcome of these matters cannot be determined at this time. energySMART In 2014, the Illinois Commission approved Nicor Gas' energySMART through 2017, which outlined energy efficiency program offerings and therm reduction goals, and subsequently extended the program to 2021. Through December 31, 2017, Nicor Gas spent $107 million of the initial authorized expenditure of $113 million . A new four -year program began on January 1, 2018, with an additional authorized expenditure of $160 million . Unrecognized Ratemaking Amounts The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025. December 31, 2017 December 31, 2016 (in millions) Atlanta Gas Light $ 104 $ 110 Virginia Natural Gas 11 11 Elizabethtown Gas (*) 8 6 Nicor Gas 2 2 Total $ 125 $ 129 (*) See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the pending asset sale. Other Matters A wholly-owned subsidiary of the Company owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in the Company retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million , of which the cavern itself represents approximately 20% . A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome. The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with the Company's annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on the Company's financial statements. |
Joint Ownership Agreements
Joint Ownership Agreements | 12 Months Ended |
Dec. 31, 2017 | |
Jointly Owned Utility Plant Interests [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: Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities. In August 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. 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. Southern Company Gas has a 50% undivided ownership interest in the Dalton Pipeline jointly with The Williams Companies, Inc. At December 31, 2017 , Alabama Power's, Georgia Power's, Southern Power's, and Southern Company Gas' 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 Ownership Plant in Service Accumulated Depreciation CWIP (in millions) Plant Vogtle (nuclear) Units 1 and 2 45.7 % $ 3,564 $ 2,141 $ 70 Plant Hatch (nuclear) 50.1 1,321 595 87 Plant Miller (coal) Units 1 and 2 91.8 1,717 619 54 Plant Scherer (coal) Units 1 and 2 8.4 261 93 8 Plant Wansley (coal) 53.5 1,053 335 72 Rocky Mountain (pumped storage) 25.4 182 132 — Plant Stanton (combined cycle) Unit A 65.0 155 55 — Dalton Pipeline (natural gas pipeline) 50.0 241 2 13 Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $3.3 billion as of December 31, 2017 . See Note 3 under " Nuclear Construction " for additional information. Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. 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. Southern Company Gas entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years . The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. |
ALABAMA POWER CO | |
Jointly Owned Utility Plant Interests [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. SEGCO uses natural gas as the primary fuel source for 1,000 MWs of its generating capacity. 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 $76 million in 2017 , $55 million in 2016 , and $76 million in 2015 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. 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, 2017 , the capitalization of SEGCO consisted of $95 million of equity and $125 million of long-term debt on which the annual interest requirement is $4 million . In addition, SEGCO had short-term debt outstanding of $14 million . SEGCO paid $24 million of dividends in 2017 and 2016 compared to an immaterial amount in 2015 , of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net income. The Company, which owns and operates a generating unit adjacent to the SEGCO generating units, has a joint ownership agreement with SEGCO for the ownership of an associated gas pipeline. The Company owns 14% of the pipeline with the remaining 86% owned by SEGCO. In addition to the Company's ownership of SEGCO and joint ownership of an associated gas pipeline, the Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2017 were as follows: Facility Total MW Capacity Company Ownership Plant in Service Accumulated Depreciation Construction Work in Progress (in millions) Greene County 500 60.00 % (1) $ 172 $ 65 $ 2 Plant Miller Units 1 and 2 1,320 91.84 % (2) 1,717 619 54 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth Energy Cooperative, Inc. The Company has contracted to operate and maintain its 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 CO | |
Jointly Owned Utility Plant Interests [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. SEGCO uses natural gas as the primary fuel source for 1,000 MWs of its generating capacity. 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 an ROE. The Company's share of purchased power totaled $78 million in 2017 , $57 million in 2016 , and $78 million in 2015 and is included in purchased power, affiliates in the statements of income. The Company accounts for SEGCO using the equity method. See Note 7 under "Guarantees" for additional information. The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, 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, which is the operator of the plant. In August 2016, the Company sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. At December 31, 2017 , 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 45.7 % $ 3,564 $ 2,141 $ 70 Plant Hatch (nuclear) 50.1 1,321 595 87 Plant Wansley (coal) 53.5 1,053 335 72 Plant Scherer (coal) Units 1 and 2 8.4 261 93 8 Unit 3 75.0 1,232 468 26 Rocky Mountain (pumped storage) 25.4 182 132 — 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, which are currently under construction and had a CWIP balance of $3.3 billion as of December 31, 2017 . See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information. |
GULF POWER CO | |
Jointly Owned Utility Plant Interests [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 -MW 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, 2017 , the Company's percentage ownership and investment in these jointly-owned facilities were as follows: Plant Scherer Unit 3 (coal) Plant Daniel Units 1 & 2 (coal) (in millions) Plant in service $ 374 $ 696 Accumulated depreciation 147 225 Construction work in progress 9 4 Company ownership 25 % 50 % 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 CO | |
Jointly Owned Utility Plant Interests [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. At December 31, 2017 , the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows: Generating Plant Company Ownership Plant in Service Accumulated Depreciation CWIP (in millions) Greene County Units 1 and 2 40 % $ 164 $ 55 $ 1 Daniel Units 1 and 2 50 % $ 713 $ 189 $ 4 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. |
SOUTHERN POWER CO | |
Jointly Owned Utility Plant Interests [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS The Company is a 65% owner of Plant Stanton A, a natural gas-fired combined-cycle unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission ( 28% ), the Florida Municipal Power Agency ( 3.5% ), and the 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, 2017 , $155 million was recorded in plant in service with associated accumulated depreciation of $55 million . These amounts represent the Company's share of 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 consolidated statements of income. |
SOUTHERN Co GAS | |
Jointly Owned Utility Plant Interests [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS In 2014, the Company entered into a construction and ownership arrangement associated with the Dalton Pipeline through which the Company has a 50% undivided ownership interest jointly with The Williams Companies, Inc. in the 115 -mile Dalton Pipeline to serve as an extension of the Transco natural gas pipeline system into northwest Georgia. The Company also entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017 . Under the lease, the Company will receive approximately $26 million annually for an initial term of 25 years . The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. At December 31, 2017 , the net book value of the Company's 50% share of the pipeline was $252 million and is reflected in total property, plant, and equipment in the balance sheet. At December 31, 2016, the net book value of the Company's 50% share of the pipeline was $124 million and is reflected in construction work in progress in the balance sheet. Variable Interest Entities SouthStar, previously a joint venture owned 85% by the Company and 15% by Piedmont, was the only VIE for which the Company was the primary beneficiary, prior to October 2016 when the Company completed its purchase of Piedmont's remaining interest in SouthStar. In 2015, Georgia Natural Gas Company (GNG), a 100% -owned, direct subsidiary of the Company, notified Piedmont of its election, pursuant to a change in control of SouthStar, to purchase Piedmont's 15% interest in SouthStar at fair market value. This purchase was contingent upon the closing of the merger between Piedmont and Duke Energy Corporation (Duke Energy). In October 2016, after Piedmont and Duke Energy completed their merger, GNG completed its purchase of Piedmont's interest in SouthStar and paid a purchase price of $160 million and $15 million for Piedmont's share of SouthStar's 2016 earnings through the date of acquisition. At December 31, 2015, the Company presented the noncontrolling interest related to Piedmont's interest in SouthStar as a component in equity. During the first quarter 2016, the Company reclassified its noncontrolling interest, whose redemption was beyond the Company's control, as a contingently redeemable noncontrolling interest. Upon Piedmont and Duke Energy obtaining the necessary merger approval, the Company deemed this noncontrolling interest to be mandatorily redeemable and reclassified it to a current liability during the third quarter 2016. The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below: Predecessor – (in millions) Balance at December 31, 2015 $ — Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest 46 Net income attributable to noncontrolling interest 14 Distribution to noncontrolling interest (19 ) Balance at June 30, 2016 $ 41 Successor – (in millions) Balance at July 1, 2016 $ 174 Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable (174 ) Balance at December 31, 2016 $ — The Company's cash flows used for financing activities included SouthStar's distribution to Piedmont for its portion of SouthStar's annual earnings from the previous year, which generally occurred in the first quarter of each year. For the successor period of July 1, 2016 through December 31, 2016 , SouthStar made a distribution of $15 million upon completion of the purchase of Piedmont's interest in SouthStar. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , SouthStar distributed to Piedmont $19 million and $18 million , respectively. Equity Method Investments The carrying amounts of the Company's equity method investments as of December 31, 2017 and 2016 and related income from those investments for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were as follows: Balance Sheet Information December 31, 2017 December 31, 2016 (in millions) SNG (*) $ 1,262 $ 1,394 Triton 42 44 Horizon Pipeline 30 30 PennEast Pipeline 57 22 Atlantic Coast Pipeline 41 33 Pivotal JAX LNG, LLC 44 16 Other 1 2 Total $ 1,477 $ 1,541 (*) Includes a $104 million decrease at December 31, 2017 related to the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. Successor Predecessor Income Statement Information Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) SNG $ 88 $ 56 $ — $ — Triton 4 2 1 4 Horizon Pipeline 2 1 1 2 Atlantic Coast Pipeline 6 1 — — PennEast Pipeline 6 — — — Total $ 106 $ 60 $ 2 $ 6 SNG In September 2016, the Company, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. See Note 11 under "Investment in SNG" for additional information. Selected financial information of SNG as of December 31, 2017 and 2016 and for the year ended December 31, 2017 and for the period September 1, 2016 through December 31, 2016 is as follows: As of December 31, Balance Sheet Information 2017 2016 (in millions) Current assets $ 82 $ 95 Property, plant, and equipment 2,439 2,451 Deferred charges and other assets 121 129 Total Assets $ 2,642 $ 2,675 Current liabilities $ 110 $ 588 Long-term debt 1,102 706 Other deferred charges and other liabilities 76 22 Total Liabilities $ 1,288 $ 1,316 Total Stockholders' Equity 1,354 1,359 Total Liabilities and Stockholders' Equity $ 2,642 $ 2,675 Income Statement Information Year ended December 31, 2017 September 1, 2016 (in millions) Revenues $ 544 $ 230 Operating income 246 138 Net income $ 175 $ 115 Other Investments Triton The Company has an investment in Triton, a cargo container leasing company, which is aggregated into its all other segment. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton's operating agreement and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2017 , the Company had invested in seven tranches established by Triton. Horizon Pipeline The Company owns an interest in a joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC. Horizon Pipeline operates a 70 -mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total annual capacity. PennEast Pipeline In 2014, the Company entered into a partnership in which it holds a 20% ownership interest in an interstate pipeline company formed to develop and operate a 118 -mile natural gas pipeline between New Jersey and Pennsylvania. The initial transportation capacity of 1.0 billion cubic feet (Bcf) per day, is under long-term contracts, mainly by public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York. On January 19, 2018, the PennEast Pipeline project received FERC approval. Atlantic Coast Pipeline In 2014, the Company entered into a project in which it holds a 5% ownership interest in an interstate pipeline company formed to develop and operate a 594 -mile natural gas pipeline in North Carolina, Virginia, and West Virginia with initial transportation capacity of 1.5 Bcf per day. On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval. Pivotal JAX LNG, LLC The Company owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida. Once construction is complete and the facility is operational, it will be outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. 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. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Federal Tax Reform Legislation Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current $ (62 ) $ 1,184 $ (177 ) Deferred (6 ) (342 ) 1,266 (68 ) 842 1,089 State — Current 37 (108 ) (33 ) Deferred 173 217 138 210 109 105 Total $ 142 $ 951 $ 1,194 Net cash payments (refunds) for income taxes in 2017 , 2016 , and 2015 were $(410) million , $(148) million , and $(9) 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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 10,267 $ 15,392 Property basis differences 955 2,708 Leveraged lease basis differences 251 314 Employee benefit obligations 516 737 Premium on reacquired debt 54 89 Regulatory assets associated with employee benefit obligations 1,046 1,584 Regulatory assets associated with AROs 1,225 1,781 Other 697 907 Total 15,011 23,512 Deferred tax assets — Federal effect of state deferred taxes 326 597 Employee benefit obligations 1,307 1,868 Over recovered fuel clause — 66 Other property basis differences 446 401 Deferred costs 69 100 ITC carryforward 2,420 1,974 Federal NOL carryforward 518 1,084 Unbilled revenue 57 92 Other comprehensive losses 84 152 AROs 1,197 1,732 Estimated Loss on Kemper IGCC 722 484 Deferred state tax assets 328 266 Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) 465 — Other 485 679 Total 8,424 9,495 Valuation allowance (149 ) (23 ) Total deferred income taxes 6,736 14,040 Portion included in accumulated deferred tax assets (106 ) (52 ) Accumulated deferred income taxes $ 6,842 $ 14,092 The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities. At December 31, 2017 , the tax-related regulatory assets to be recovered from customers were $825 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, 2017 , the tax-related regulatory liabilities to be credited to customers were $7.3 billion . 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 for the traditional electric operating companies and the natural gas distribution utilities 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 2017 , $22 million in 2016 , and $21 million in 2015 . Southern Power's deferred federal ITCs are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $57 million in 2017 , $37 million in 2016 , and $19 million in 2015 . Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015 . No cash was received related to these incentives in 2017 and 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs 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 $18 million in 2017 , $173 million in 2016 , and $54 million in 2015 . See " Unrecognized Tax Benefits " below for further information. Tax Credit Carryforwards At December 31, 2017 , Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $2.1 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time. Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling approximately $318 million , which will expire between 2020 and 2027 but are expected to be fully utilized. Net Operating Loss After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017 . The federal NOL will begin expiring in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time. At December 31, 2017 , the state NOL carryforwards for Southern Company's subsidiaries were as follows: Jurisdiction Approximate NOL Carryforwards Approximate Net State Income Tax Benefit Tax Year NOL Begins Expiring (in millions) Mississippi $ 2,890 $ 114 2032 Oklahoma 986 47 2036 Georgia 524 23 2019 New York 229 13 2036 New York City 209 15 2036 Florida 304 13 2034 Other states 465 24 Various Total $ 5,607 $ 249 Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 12.5 2.1 1.9 Employee stock plans dividend deduction (4.1 ) (1.2 ) (1.2 ) Non-deductible book depreciation 3.1 0.9 1.2 AFUDC-Equity (2.6 ) (2.0 ) (2.2 ) Non-deductible equity portion on Kemper IGCC write-off 15.7 — — ITC basis difference (1.7 ) (5.0 ) (1.5 ) Federal PTCs (12.1 ) (1.2 ) — Amortization of ITC (4.2 ) (0.9 ) (0.5 ) Tax Reform Legislation (25.6 ) — — Other (2.7 ) (0.4 ) 0.2 Effective income tax rate 13.3 % 27.3 % 32.9 % Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs. However, in 2017, the effective tax rate was primarily lower due to the remeasurement of deferred income taxes resulting from the Tax Reform Legislation. In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company's overall effective tax rate. See Note 1 under " Recently Issued Accounting Standards " for additional information. Legal Entity Reorganization In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2017 2016 2015 (in millions) Unrecognized tax benefits at beginning of year $ 484 $ 433 $ 170 Tax positions increase from current periods 10 45 43 Tax positions increase from prior periods 10 21 240 Tax positions decrease from prior periods (196 ) (15 ) (20 ) Reductions due to settlements (290 ) — — Balance at end of year $ 18 $ 484 $ 433 The tax positions increase from current and prior periods for 2017 and 2016 relate primarily to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as deductions for R&E expenditures associated with the Kemper County energy facility. The tax positions decrease from prior periods for 2017 and 2016 , and the reductions due to settlements for 2017 , relate primarily to the settlement of R&E expenditures associated with the Kemper County energy facility and federal income tax benefits from deferred ITCs. See Note 3 under " Kemper County Energy Facility " and " Section 174 Research and Experimental Deduction " herein for more information. The impact on Southern Company's effective tax rate, if recognized, is as follows: 2017 2016 2015 (in millions) Tax positions impacting the effective tax rate $ 18 $ 20 $ 10 Tax positions not impacting the effective tax rate — 464 423 Balance of unrecognized tax benefits $ 18 $ 484 $ 433 The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility and Southern Company's estimate of the uncertainty related to the amount of those benefits. The tax positions not impacting the effective tax rate for 2016 and 2015 relate to deductions for R&E expenditures associated with the Kemper County energy facility. See " Section 174 Research and Experimental Deduction " herein for more information. These amounts are presented on a gross basis without considering the related federal or state income tax impact. Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented. Southern Company classifies interest on tax uncertainties as interest expense. 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 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. 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 2011. Section 174 Research and Experimental Deduction Southern Company has reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. As a result of this approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. |
ALABAMA POWER CO | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. 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. Federal Tax Reform Legislation Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Retail Regulatory Matters – Rate RSE" for additional information. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current $ 136 $ 103 $ 110 Deferred 336 339 320 472 442 430 State — Current 23 20 8 Deferred 73 69 68 96 89 76 Total $ 568 $ 531 $ 506 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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 2,336 $ 4,307 Property basis differences 398 456 Premium on reacquired debt 16 26 Employee benefit obligations 162 201 Regulatory assets associated with employee benefit obligations 260 393 Asset retirement obligations 220 289 Regulatory assets associated with asset retirement obligations 249 347 Other 147 179 Total 3,788 6,198 Deferred tax assets — Federal effect of state deferred taxes 143 266 Unbilled fuel revenue 22 36 Storm reserve 5 21 Employee benefit obligations 286 427 Other comprehensive losses 10 19 Asset retirement obligations 469 636 Other 93 139 Total 1,028 1,544 Accumulated deferred income taxes, net $ 2,760 $ 4,654 The implementation of Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the 2015 Protecting Americans from Tax Hikes Act. Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities. At December 31, 2017 , the tax-related regulatory assets to be recovered from customers were $240 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, 2017 , the tax-related regulatory liabilities to be credited to customers were $2.1 billion . 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 $7 million in 2017 and $8 million annually in 2016 and 2015. At December 31, 2017 , the Company had federal ITC carryforwards which are expected to result in $9 million of federal income tax benefits. The federal ITC carryforwards begin expiring in 2038 but are expected to be fully utilized by 2027. The ultimate outcome of these matters cannot be determined at this time. Tax Credit Carryforwards The Company had state credit carryforwards for the state of Alabama of approximately $4 million , which begin expiring in 2023 but are expected to be fully utilized. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.4 4.2 3.8 Non-deductible book depreciation 0.9 1.0 1.2 AFUDC equity (1.0) (0.7) (1.6) Tax Reform Legislation 0.3 — — Other — (0.7) — Effective income tax rate 39.6% 38.8% 38.4% In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under " Recently Issued Accounting Standards " for additional information. Unrecognized Tax Benefits The Company has no material unrecognized tax benefits for the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and 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 2016. 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. |
GEORGIA POWER CO | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. 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. Federal Tax Reform Legislation Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Retail Regulatory Matters – Rate Plans" for additional information. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal – Current $ 256 $ 391 $ 515 Deferred 504 319 176 760 710 691 State – Current 116 6 81 Deferred (46 ) 64 (3 ) 70 70 78 Total $ 830 $ 780 $ 769 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: 2017 2016 (in millions) Deferred tax liabilities – Accelerated depreciation $ 3,540 $ 5,266 Property basis differences — 957 Employee benefit obligations 287 428 Premium on reacquired debt 34 56 Regulatory assets – Storm damage reserves 89 83 Employee benefit obligations 348 546 Asset retirement obligations 501 726 Retired assets 30 55 Asset retirement obligations 132 182 Other 100 83 Total 5,061 8,382 Deferred tax assets – Federal effect of state deferred taxes 72 173 Employee benefit obligations 423 661 Property basis differences 92 105 Other deferred costs 69 100 State investment tax credit carryforward 318 201 Federal tax credit carryforward 97 84 Unbilled fuel revenue 26 47 Regulatory liabilities associated with asset retirement obligations 5 33 Asset retirement obligations 631 908 Regulatory liability associated with Tax Reform Legislation (not subject to normalization) 123 — Other 30 70 Total 1,886 2,382 Accumulated deferred income taxes $ 3,175 $ 6,000 The implementation of Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions of the Protecting Americans from Tax Hikes Act. Tax Reform Legislation also reduced tax-related regulatory assets and significantly increased tax-related regulatory liabilities. At December 31, 2017 , tax-related regulatory assets to be recovered from customers were $521 million . These assets are primarily attributable to tax benefits flowed through to customers in prior years and deferred taxes previously recognized at rates lower than the current enacted tax law. At December 31, 2017 , tax-related regulatory liabilities to be credited to customers were $3.2 billion . These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law. In accordance with regulatory requirements, federal ITCs are deferred and, upon utilization, 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 each of 2017 , 2016 , and 2015 . State investment tax credits are recognized in the period in which the credits are generated and totaled $50 million in 2017 , $42 million in 2016 , and $33 million in 2015 . At December 31, 2017 , the Company had $87 million in federal ITC carryforwards that will expire by 2037 and $318 million in state ITC carryforwards that will expire between 2020 and 2028. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 2.0 2.1 2.5 Non-deductible book depreciation 0.7 0.8 1.2 AFUDC equity (0.6 ) (0.8 ) (0.7 ) Tax Reform Legislation (0.4 ) — — Other — (0.4 ) (0.4 ) Effective income tax rate 36.7 % 36.7 % 37.6 % In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits The Company had no material unrecognized tax benefits as of December 31, 2017 and no material changes in unrecognized tax benefits for any year presented. The Company classifies interest on tax uncertainties as interest expense; however, the Company did not have any accrued interest or penalties for unrecognized tax benefits for any year presented. 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 2016. 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. |
GULF POWER CO | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. 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. Federal Tax Reform Legislation Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Retail Regulatory Matters" for additional information. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal - Current $ 19 $ 34 $ (3 ) Deferred 58 45 80 77 79 77 State - Current (1 ) — 5 Deferred 14 12 10 13 12 15 Total $ 90 $ 91 $ 92 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: 2017 2016 (in millions) Deferred tax liabilities- Accelerated depreciation $ 552 $ 834 Property basis differences 105 123 Pension and other employee benefits 38 58 Regulatory assets 22 45 Regulatory assets associated with employee benefit obligations 44 65 Regulatory assets associated with asset retirement obligations 38 55 Other 13 12 Total 812 1,192 Deferred tax assets- Federal effect of state deferred taxes 25 37 Postretirement benefits 17 26 Pension and other employee benefits 49 72 Property differences 98 1 Regulatory liability associated with Tax Reform Legislation (not subject to normalization) 19 — Property reserve 10 17 Asset retirement obligations 38 55 Alternative minimum tax carryforward 7 18 Other 12 18 Total 275 244 Accumulated deferred income taxes $ 537 $ 948 The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities. At December 31, 2017 , tax-related regulatory assets to be recovered from customers were $31 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, 2017 , the tax-related regulatory liabilities to be credited to customers were $458 million . These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and unamortized ITCs. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.7 3.4 3.9 Non-deductible book depreciation 0.2 0.6 0.5 Differences in prior years' deferred and current tax rates — (0.1) (0.1) AFUDC equity — — (1.8) Other, net 0.5 0.6 (0.6) Effective income tax rate 39.4% 39.5% 36.9% In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits The Company has no material unrecognized tax benefits for the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and 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, but an estimate of the range of reasonably possible outcomes cannot be determined at this time. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. 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. |
MISSISSIPPI POWER CO | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. 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. Federal Tax Reform Legislation Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current $ 194 $ (31 ) $ (768 ) Deferred (753 ) (60 ) 704 (559 ) (91 ) (64 ) State — Current — (6 ) (81 ) Deferred 27 (7 ) 73 27 (13 ) (8 ) Total $ (532 ) $ (104 ) $ (72 ) 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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 373 $ 386 Property basis difference 242 852 Regulatory assets associated with AROs 34 72 Pensions and other benefits 28 49 Regulatory assets associated with employee benefit obligations 45 70 Regulatory assets associated with the Kemper County energy facility 31 82 Regulatory assets associated with Plant Daniel 9 13 Rate differential — 141 Federal effect of state deferred taxes 9 — Ad valorem over/under recovery 11 14 Regulatory assets for Mercury and Air Toxics Standards compliance 11 8 Other 11 91 Total 804 1,778 Deferred tax assets — Fuel clause over recovered — 26 Estimated loss on Kemper IGCC 722 484 Pension and other benefits 62 96 Federal NOL 40 109 Property insurance 15 27 Premium on long-term debt 7 14 AROs 34 72 Property basis difference 70 — Affirmative adjustments 31 — Regulatory liability associated with Tax Reform Legislation (not subject to normalization) 27 — Deferred state tax assets 133 113 Deferred federal tax assets — 31 Federal effect of state deferred taxes — 19 Other 32 31 Total 1,173 1,022 Valuation allowance (net of $35 million in federal benefit) 122 — Accumulated deferred income tax (assets)/liabilities (247 ) 756 The implementation of Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities. At December 31, 2017 , the tax-related regulatory assets were $36 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, 2017 , the tax-related regulatory liabilities were $376 million . These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and 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 County energy facility related deferred ITCs amortized in this manner amounted to $1 million in each of 2017, 2016, and 2015. At December 31, 2017 , the Company had state of Mississippi NOL carryforwards totaling approximately $2.8 billion , resulting in deferred tax assets of approximately $111 million . The NOLs will expire between 2031 and 2037. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate (35.0 )% (35.0 )% (35.0 )% State income tax, net of federal deduction 0.6 (5.7 ) (6.3 ) Non-deductible book depreciation 0.1 0.7 1.3 AFUDC-equity — (28.5 ) (49.6 ) Non-deductible equity portion on Kemper IGCC write-off 5.3 — — Tax Reform Legislation 11.9 — — Other — — (2.9 ) Effective income tax rate (benefit rate) (17.1 )% (68.5 )% (92.5 )% The decrease in the Company's 2017 effective tax rate (benefit rate), as compared to 2016, is primarily due to an increase in estimated losses associated with the Kemper IGCC, a decrease in non-taxable AFUDC equity, and a decrease due to the remeasurement of deferred income taxes resulting from Tax Reform Legislation. The decrease in the Company's 2016 effective tax rate (benefit rate), as compared to 2015, is primarily due to an increase in estimated losses associated with the Kemper IGCC and an increase in non-taxable AFUDC equity. Tax Reform Legislation reduced the corporate income tax rate from 35% to 21% . As a result of implementation, the Company restated future tax benefits/deductions recorded as deferred tax assets/liabilities to reflect the new rate. The implementation resulted in a $372 million increase in tax expense and a $375 million increase in regulatory liabilities. In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2017 2016 2015 (in millions) Unrecognized tax benefits at beginning of year $ 465 $ 421 $ 165 Tax positions increase from current periods — 26 32 Tax positions increase from prior periods 2 18 224 Tax positions decrease from prior periods (177 ) — — Reductions due to settlements (290 ) — — Balance at end of year $ — $ 465 $ 421 The tax positions increases from current periods and prior periods for 2017, 2016 and 2015 relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as federal income tax benefits from deferred ITCs. The tax positions decrease from prior periods and reductions due to settlements for 2017 relate primarily to the settlement of R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact. The impact on the Company's effective tax rate, if recognized, is as follows: 2017 2016 2015 (in millions) Tax positions impacting the effective tax rate $ — $ 1 $ (2 ) Tax positions not impacting the effective tax rate — 464 423 Balance of unrecognized tax benefits $ — $ 465 $ 421 The tax positions not impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for additional information. Accrued interest for unrecognized tax benefits was as follows: 2017 2016 2015 (in millions) Interest accrued at beginning of year $ 28 $ 13 $ 3 Interest accrued during the year (28 ) 15 10 Balance at end of year $ — $ 28 $ 13 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 2016. 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. Section 174 Research and Experimental Deduction Southern Company, on behalf of the Company, has reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. |
SOUTHERN POWER CO | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined, unitary, or consolidated. 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. Federal Tax Reform Legislation Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current (*) $ (566 ) $ 928 $ 12 Deferred (*) (312 ) (1,098 ) 10 (878 ) (170 ) 22 State — Current (110 ) (60 ) (32 ) Deferred 49 35 31 (61 ) (25 ) (1 ) Total $ (939 ) $ (195 ) $ 21 (*) ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $316 million for 2017 , $1.13 billion for 2016 , and $246 million for 2015. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits. 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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation and other property basis differences $ 1,922 $ 2,440 Levelized capacity revenues 26 28 Other 6 27 Total deferred income tax liabilities 1,954 2,495 Deferred tax assets — Federal effect of state deferred taxes 42 53 Basis difference on ITCs 184 292 Alternative minimum tax carryforward 21 15 Unrealized tax credits 2,002 1,685 Federal net operating loss (NOL) 333 808 Deferred state tax assets 77 60 Other partnership basis differences 24 16 Other 10 8 Total deferred income tax assets 2,693 2,937 Valuation Allowance (13 ) — Net deferred income tax assets 2,680 2,937 Total deferred income tax asset (liability) $ 726 $ 442 Recognized in the consolidated balance sheets: Accumulated deferred income taxes – assets $ 925 $ 594 Accumulated deferred income taxes – liability $ (199 ) $ (152 ) Deferred tax liabilities are primarily the result of property-related timing differences, which increased due to bonus depreciation. However, the implementation of the Tax Reform Legislation significantly reduced the amount of accumulated deferred income taxes at December 31, 2017. Deferred tax assets consist primarily of timing differences related to the carryforward of unrealized federal ITCs, PTCs, net operating loss, and net basis differences on federal ITCs. Tax Credit Carryforwards At December 31, 2017, the Company had federal ITC and PTC carryforwards, which are expected to result in $2.0 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2036 but are also expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay the utilization of existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time. Net Operating Loss After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will expire in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time. The Company had state NOL carryforwards of approximately $1.3 billion at December 31, 2017, which will expire from 2029 to 2035. These carryforwards resulted in deferred tax assets of approximately $61 million as of December 31, 2017. The state NOL carryforwards by state jurisdiction were as follows: Jurisdiction Approximate NOL Carryforwards Approximate Net State Income Tax Benefit Tax Year NOL Expires (in millions) Oklahoma $ 978 $ 46 2035 Florida 283 12 2033 South Carolina 48 2 2035 Other states 23 1 2029-2035 Balance at year end $ 1,332 $ 61 Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction (22.2 ) (9.1 ) (0.3 ) Amortization of ITC (31.8 ) (20.6 ) (5.0 ) ITC basis difference (10.0 ) (89.0 ) (21.5 ) Production tax credits (72.5 ) (23.3 ) (0.6 ) Tax Reform Legislation (416.1 ) — — Noncontrolling interests (8.6 ) (6.2 ) (1.7 ) Other 0.5 4.6 2.5 Effective income tax rate (benefit) (525.7 )% (108.6 )% 8.4 % The Company's effective tax rate decreased in 2017 primarily due to the Tax Reform Legislation. The decrease in 2016 was primarily due to changes in federal ITCs and PTCs. The Company's deferred federal ITCs are amortized to income tax expense over the life of the respective asset. ITCs amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, the Company received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015. While no cash was received related to these incentives in 2017 or 2016, the Company recognized tax credits. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs 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. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015. The tax benefit of PTCs reduced income tax expense by $129 million in 2017, $42 million in 2016 and $1 million in 2015. See "Unrecognized Tax Benefits" herein for further information. Legal Entity Reorganization In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of the solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2017 2016 2015 (in millions) Balance at beginning of year $ 17 $ 8 $ 5 Tax positions increase from current periods — 17 9 Tax positions decrease from prior periods (17 ) (8 ) (6 ) Balance at end of year $ — $ 17 $ 8 The increase in unrecognized tax benefits from current periods for all years presented, and the decrease from prior periods for all years presented, primarily relate to federal income tax benefits from deferred ITCs and would all impact the Company's effective tax rate, if recognized. The impact on the effective tax rate is determined based on the amount of ITCs which are uncertain. 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 no t 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 2016. 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. |
SOUTHERN Co GAS | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES Subsequent to the Merger, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns on behalf of the Company. 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. Prior to the Merger, the Company filed a U.S. federal consolidated income tax return and various state income tax returns. Federal Tax Reform Legislation Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. Current and Deferred Income Taxes Details of income tax provisions are as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) Federal — Current $ 103 $ — $ 67 $ (13 ) Deferred 170 65 8 198 273 65 75 185 State — Current 27 (16 ) 12 10 Deferred 67 27 — 18 94 11 12 28 Total $ 367 $ 76 $ 87 $ 213 Net cash payments (refunds) for income taxes for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $72 million , $23 million , $(100) million , and $(26) 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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 1,436 $ 1,954 Property basis differences 204 311 Regulatory assets associated with employee benefit obligations 79 125 Other 208 164 Total 1,927 2,554 Deferred tax assets — Federal net operating loss 92 59 Federal effect of state deferred taxes 54 42 Employee benefit obligations 185 165 Regulatory liability associated with the Tax Reform Legislation (not subject to 295 — Other 223 332 Total 849 598 Less valuation allowances (11 ) (19 ) Total, net of valuation allowances 838 579 Accumulated deferred income taxes, net $ 1,089 $ 1,975 The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly increased tax-related regulatory liabilities. At December 31, 2017 , the tax-related regulatory liabilities to be credited to customers were $1.1 billion . These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. Deferred federal and state 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 $4 million and $1 million for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , were $1 million and $2 million , respectively. At December 31, 2017 , 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: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Federal statutory rate 35.0% 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.0 4.0 3.5 3.4 Tax Reform Legislation 15.0 — — — State tax legislation and rate changes 6.2 — — — Other — 1.0 (0.9) (2.0) Effective income tax rate 60.2% 40.0% 37.6% 36.4% The principal differences in the Company's effective tax rate from December 31, 2016 to December 31, 2017 include the impact of the Tax Reform Legislation, the Illinois income tax legislation enacted in the third quarter 2017, new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings, the disallowance of certain nondeductible Merger-related expenses associated with change-in-control compensation charges, and an increase in earnings before income taxes. Unrecognized Tax Benefits The Company has no unrecognized tax benefits for any period presented. The Company classifies interest on tax uncertainties as interest expense; however, the Company had no accrued interest or penalties for unrecognized tax benefits for any period presented. 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. On July 1, 2016, the Company became a wholly-owned subsidiary of Southern Company, which is a participant in the Compliance Assurance Process of the IRS. The IRS has finalized its audits of Southern Company's consolidated federal tax returns through 2016. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for the Company by any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for years prior to 2011. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2017 | |
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 2017 , 2016 , and 2015 , the traditional electric operating companies and Southern Power incurred fuel expense of $4.4 billion , $4.4 billion , and $4.8 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 $235 million , $232 million , and $227 million for 2017 , 2016 , and 2015 , respectively. Estimated total obligations under these commitments at December 31, 2017 were as follows: Operating Leases Other (in millions) 2018 $ 247 $ 7 2019 250 6 2020 247 4 2021 249 5 2022 252 4 2023 and thereafter 806 38 Total $ 2,051 $ 64 Pipeline Charges, Storage Capacity, and Gas Supply Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million . Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2018 $ 813 2019 552 2020 416 2021 375 2022 339 2023 and thereafter 2,294 Total $ 4,789 Operating Leases The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $176 million , $169 million , and $130 million for 2017 , 2016 , and 2015 , respectively. Southern Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments. As of December 31, 2017 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Barges & Railcars Other (*) Total (in millions) 2018 $ 21 $ 128 $ 149 2019 11 113 124 2020 9 99 108 2021 8 87 95 2022 6 77 83 2023 and thereafter 5 963 968 Total $ 60 $ 1,467 $ 1,527 (*) Includes operating leases for cellular tower space, facilities, vehicles, and other equipment. For the traditional electric 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 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 $44 million . At the termination of the leases, the lessee may renew the lease, 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 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 2018 . 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 CO | |
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 2017, 2016, and 2015, the Company incurred fuel expense of $1.2 billion , $1.3 billion , and $1.3 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 $41 million , $42 million , and $38 million for 2017, 2016, and 2015, respectively. Total estimated minimum long-term obligations at December 31, 2017 were as follows: Operating Lease PPAs (in millions) 2018 $ 41 2019 43 2020 44 2021 46 2022 47 2023 and thereafter — Total commitments $ 221 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 electric operating companies and Southern Power. Under these agreements, each of the traditional electric 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 electric 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 operating leases with Southern Linc and third parties for the use of cellular tower space. Substantially all of these agreements have initial terms ranging from five to 10 years and renewal options of up to 20 years . The Company has entered into rental agreements for towers, coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense under these agreements was $25 million in 2017 , $18 million in 2016 , and $19 million in 2015 . Of these amounts, $11 million , $14 million , and $13 million for 2017, 2016, and 2015, respectively, relate to the railcar leases and was recovered through the Company's Rate ECR. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments. As of December 31, 2017 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments (a) Affiliate Operating Leases (b) Railcars Vehicles & Other Total (in millions) 2018 $ 8 $ 7 $ 6 $ 21 2019 10 7 5 22 2020 8 7 3 18 2021 7 6 1 14 2022 5 5 — 10 2023 and thereafter 16 4 — 20 Total $ 54 $ 36 $ 15 $ 105 (a) Minimum lease payments have not been reduced by minimum sublease rentals of $3 million in the future. (b) Includes operating leases for cellular tower space. In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain railcar 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 $12 million in 2023. There are no obligations under these leases through 2022. 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 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 CO | |
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 2017 , 2016 , and 2015 , the Company incurred fuel expense of $1.7 billion , $1.8 billion , and $2.0 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 Units 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 $9 million , $11 million , and $10 million in 2017 , 2016 , and 2015 , 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 $199 million , $217 million , and $203 million for 2017 , 2016 , and 2015 , respectively. Contingent rent expense under energy-only solar PPAs of $73 million , $39 million , and $8 million for 2017 , 2016 , and 2015 , respectively, was recognized as services were performed. Estimated total long-term obligations at December 31, 2017 were as follows: Affiliate Capital Leases Affiliate Operating Leases Non-Affiliate Operating Leases Vogtle Units 1 and 2 Capacity Payments Total (in millions) 2018 $ 23 $ 62 $ 127 $ 7 $ 219 2019 23 63 128 6 220 2020 23 65 124 4 216 2021 24 66 125 5 220 2022 24 67 126 4 221 2023 and thereafter 182 412 773 38 1,405 Total $ 299 $ 735 $ 1,403 $ 64 $ 2,501 Less: amounts representing executory costs (a) 45 Net minimum lease payments 254 Less: amounts representing interest (b) 120 Present value of net minimum lease payments $ 134 (a) Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) a re estimated and included in total minimum lease payments. (b) Calculated using an adjusted incremental borrowing rate to reduce the present value of the net minimum lease payments to fair value. 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 electric operating companies and Southern Power. Under these agreements, each of the traditional electric 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 electric 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 operating leases with Southern Linc and third parties for the use of cellular tower space. Substantially all of these agreements have initial terms ranging from five to 10 years and renewal options of up to 20 years . The Company has also entered into rental agreements for facilities, railcars, and other equipment with various terms and expiration dates. Total rent expense was $31 million , $28 million , and $29 million for 2017 , 2016 , and 2015 , respectively. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments. As of December 31, 2017 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Affiliate Operating Leases (a) Non-Affiliate Operating Leases (b) Total (in millions) 2018 $ 10 $ 14 $ 24 2019 11 11 22 2020 11 9 20 2021 9 8 17 2022 8 6 14 2023 and thereafter 33 11 44 Total $ 82 $ 59 $ 141 (a) Includes operating leases for cellular tower space. (b) Includes operating leases for cellular tower space, facilities, railcars, and other equipment. 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 Company 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 reduce 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 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 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 2018 . 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 CO | |
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 2017 , 2016 , and 2015 , the Company incurred fuel expense of $427 million , $432 million , and $445 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 a PPA accounted for as an operating lease was $75 million each year for 2017 , 2016 , and 2015 . Estimated total minimum long-term commitments at December 31, 2017 were as follows: Operating Lease PPA (in millions) 2018 $ 79 2019 79 2020 79 2021 79 2022 79 2023 and thereafter 33 Total $ 428 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 electric operating companies and Southern Power. Under these agreements, each of the traditional electric 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 electric 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 PPA discussed above, the Company has entered into operating leases with Southern Linc and other third parties for the use of cellular tower space. These agreements have initial terms ranging from five to 10 years and renewal options of up to five years. The Company also has other operating lease agreements with various terms and expiration dates. Total lease payments were $10 million , $9 million , and $14 million for 2017 , 2016 , and 2015 , respectively. The Company includes any step rents, fixed escalations, and reasonably assured renewal periods in its computation of minimum lease payments. Estimated total minimum lease payments under these operating leases at December 31, 2017 were as follows: Minimum Lease Payments Affiliate Operating Leases (a) Non-Affiliate Operating Leases (b) Total (in millions) 2018 $ 2 $ 7 $ 9 2019 1 1 2 2020 1 1 2 2021 1 — 1 2022 1 — 1 2023 and thereafter 4 1 5 Total $ 10 $ 10 $ 20 (a) Includes operating leases for cellular tower space. (b) Includes operating leases for barges, facilities, and other equipment. The Company also has operating lease agreements for railcars, barges, and towboats for the transport of coal. The Company has the option to renew the leases at the end of the lease term. The Company's lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, were $7 million in 2017 , $5 million in 2016 , and $10 million in 2015 . The Company's annual barge and towboat payments for 2018 are expected to be approximately $6 million . |
MISSISSIPPI POWER CO | |
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 2017 , 2016 , and 2015 , the Company incurred fuel expense of $395 million , $343 million , and $443 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 all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric 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 electric 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. In addition, the Company has entered into various long-term commitments for the purchase of energy through PPAs associated with solar facilities. The energy related costs associated with PPAs are recovered through the fuel cost recovery clause. Operating Leases The Company has entered into operating leases with Southern Linc and third parties for the use of cellular tower space. These agreements have initial terms ranging from five to 10 years and renewal options of up to 20 years . The Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $3 million , $3 million , and $5 million for 2017 , 2016 , and 2015 , respectively. The Company includes any step rents, fixed escalations, lease concessions, and reasonably assured renewal periods in its computation of minimum lease payments. Estimated minimum lease payments under operating leases at December 31, 2017 were as follows: Affiliate Operating Leases (a) Non-Affiliate Operating Lease (b) Total (in millions) 2018 $ 2 $ 1 $ 3 2019 2 1 3 2020 2 1 3 2021 2 — 2 2022 2 — 2 2023 and thereafter 7 — 7 Total $ 17 $ 3 $ 20 (a) Includes operating leases with affiliates primarily related to cellular towers. (b) Primarily includes railcar and fuel handling equipment leases for Plant Daniel. In addition to the above rental commitments, the Company entered into operating lease agreements for aluminum railcars for the transportation of coal at Plant Daniel, which is jointly owned with Gulf Power. 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 also has separate lease agreements for other railcars that do not contain a purchase option. The Company's 50% share of the lease costs, charged to fuel stock and recovered through the fuel cost recovery clause, was $1 million in 2017 , $2 million in 2016 , and $2 million in 2015 . In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plant Daniel. The Company's 50% share of the leases for fuel handling was charged to fuel handling expense annually from 2015 through 2017 ; however, those amounts were immaterial for the reporting period. |
SOUTHERN POWER CO | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Fuel Agreements SCS, as agent for the Company and the traditional electric operating companies, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the Company's generating facilities. These purchase obligations are not recognized on the Company's consolidated balance sheets. The Company incurred fuel expense of $621 million , $456 million , and $441 million for the years ended December 31, 2017 , 2016 , and 2015 , 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 electric operating companies. Under these agreements, each of the traditional electric operating companies and the Company may be jointly and severally liable. Southern Company has entered into keep-well agreements with each of the traditional electric 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 $29 million , $22 million , and $7 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. These amounts include contingent rent expense related to land leases based on wind production and escalation in the Consumer Price Index for All Urban Consumers. The Company excludes contingent rent but includes step rents, fixed escalations, lease concessions, and lease extensions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. As of December 31, 2017 , estimated minimum lease payments under operating leases were $22 million in each of 2018 , 2019 , and 2020 , $23 million in each of 2021 and 2022 , and $815 million in 2023 and thereafter. The majority of the committed future expenditures are related to land leases for solar and wind facilities. Redeemable Noncontrolling Interests See Note 10. |
SOUTHERN Co GAS | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Pipeline Charges, Storage Capacity, and Gas Supply Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to Marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas' and SouthStar's gas commodity purchase commitments of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million . The Company provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2018 $ 813 2019 552 2020 416 2021 375 2022 339 2023 and thereafter 2,294 Total $ 4,789 Operating Leases The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $15 million , $8 million , $6 million , and $12 million for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , respectively. The 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 terms. As of December 31, 2017 , the Company's estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments (in millions) 2018 $ 17 2019 16 2020 16 2021 15 2022 13 2023 and thereafter 26 Total $ 103 Financial Guarantees AGL Equipment Leasing Inc. (AEL), a wholly-owned subsidiary of the Company, holds the Company's interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation continues for the life of the Triton partnerships. Any payment is effectively limited to the net assets of AEL, which were less than $1 million at December 31, 2017 . The Company believes the likelihood of any such payment by AEL is remote and, as such, no liability has been recorded for this obligation at December 31, 2017 . |
Financing
Financing | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Securities Due Within One Year A summary of scheduled maturities of securities due within one year at December 31 was as follows: 2017 2016 (in millions) Senior notes $ 2,354 $ 1,995 Other long-term debt 1,420 485 Revenue bonds (*) 90 76 Capitalized leases 31 32 Unamortized debt issuance expense/discount (3 ) (1 ) Total $ 3,892 $ 2,587 (*) Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. Maturities through 2022 applicable to total long-term debt are as follows: $3.9 billion in 2018 ; $3.2 billion in 2019 ; $3.2 billion in 2020 ; $3.1 billion in 2021 ; and $2.2 billion in 2022 . Bank Term Loans Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs. At December 31, 2017 , Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $450 million , $45 million , $250 million , $900 million , and $420 million , respectively, of which $1.5 billion are reflected in the statements of capitalization as long-term debt and $600 million are reflected in the balance sheet as notes payable. At December 31, 2016 , Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million , $45 million , $100 million , $1.2 billion , and $380 million , respectively, of which $2.0 billion were reflected in the statements of capitalization as long-term debt and $100 million were reflected in the balance sheet as notes payable. In June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one -month LIBOR. In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million , with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank loan of $100 million , with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days ' demand by the bank. In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one -month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017. In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018. In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The outstanding bank loans as of December 31, 2017 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017 , each of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company 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 the Loan Guarantee Agreement in 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. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses). Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements. Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for 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 . On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. 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. In addition to the conditions described above, 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, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. Upon satisfaction of all conditions described above, 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% . At both December 31, 2017 and 2016 , Georgia Power had $2.6 billion of borrowings outstanding under the FFB Credit Facility. 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). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. 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. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, 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 $4.0 billion of senior notes in 2017 . Southern Company issued $0.3 billion and its subsidiaries issued a total of $3.7 billion . The proceeds of Southern Company's issuances were used to repay short-term indebtedness and for other general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' 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. A portion of the proceeds of Gulf Power's senior note issuances was used to redeem all of Gulf Power's outstanding shares of preference stock. See " Redeemable Preferred Stock of Subsidiaries " herein for additional information. At December 31, 2017 and 2016 , Southern Company and its subsidiaries had a total of $35.1 billion and $33.0 billion , respectively, of senior notes outstanding. At December 31, 2017 and 2016 , Southern Company had a total of $10.2 billion and $10.3 billion , respectively, of senior notes outstanding. These amounts include senior notes due within one year. 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 stockholders of such subsidiary. Junior Subordinated Notes At December 31, 2017 and 2016 , Southern Company and its subsidiaries had a total of $3.6 billion and $2.4 billion , respectively, of junior subordinated notes outstanding. In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness and for other general corporate purposes. In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077. The proceeds were used to repay short-term indebtedness and for other general corporate purposes. In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of Georgia Power's preferred and preference stock. See " Redeemable Preferred Stock of Subsidiaries " herein for additional information. Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the traditional electric 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 revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2017 and 2016 , which includes pollution control revenue bonds classified as due within one year. The traditional electric 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. Gas Facility Revenue Bonds Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas (Pivotal Utility Holdings), is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from each issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million . The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" 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 County energy facility and related facilities. Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2017 and 2016 . Such amounts are reflected in the statements of capitalization as other long-term debt. First Mortgage Bonds Nicor Gas, a subsidiary of Southern Company Gas, had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016 , respectively. These bonds have been issued with maturities ranging from 2019 to 2057. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See " Assets Subject to Lien " herein for additional information. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. 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 outstanding as of December 31, 2017 and 2016 , 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 December 31, 2017 and 2016 , trust preferred securities of $200 million were outstanding. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt. In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which resulted in a capital lease obligation of $74 million at December 31, 2016 . Following the suspension of the Kemper IGCC, Mississippi Power entered into an asset purchase and settlement agreement in December 2017 with the lessor, which terminated the capital lease obligation. See Note 3 under " Kemper County Energy Facility " for additional information. At December 31, 2017 and 2016 , the capitalized lease obligations for Georgia Power's corporate headquarters building were $22 million and $28 million , respectively, with an annual interest rate of 7.9% . At December 31, 2017 and 2016 , a subsidiary of Southern Company had capital lease obligations of approximately $177 million and $29 million , respectively, for an office building and certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.5% to 4.7% . 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 aggregate outstanding principal amount of $41 million as of December 31, 2017 . 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. On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million , located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies. 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. The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See " First Mortgage Bonds " herein for additional information. Under the terms of the PPA and the expansion PPA for Southern Power's Mankato project, which was acquired in 2016, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017 . See Note 12 under "Southern Power" for additional information. During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock solar facility in Pecos County, Texas. Roserock is in a litigation dispute with McCarthy Building Companies, Inc. (McCarthy) regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. Southern Power intends to vigorously pursue its claims against McCarthy and defend against McCarthy's claims, the ultimate outcome of which cannot be determined at this time. Bank Credit Arrangements At December 31, 2017 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year Company 2018 2019 2020 2022 Total Unused One Year Two Years Term Out No Term Out (in millions) Southern Company (a) $ — $ — $ — $ 2,000 $ 2,000 $ 1,999 $ — $ — $ — $ — Alabama Power 35 — 500 800 1,335 1,335 — — — 35 Georgia Power — — — 1,750 1,750 1,732 — — — — Gulf Power 30 25 225 — 280 280 45 — 20 10 Mississippi Power 100 — — — 100 100 — — — 100 Southern Power Company (b) — — — 750 750 728 — — — — Southern Company Gas (c) — — — 1,900 1,900 1,890 — — — — Other 30 — — — 30 30 20 — 20 10 Southern Company Consolidated $ 195 $ 25 $ 725 $ 7,200 $ 8,145 $ 8,094 $ 65 $ — $ 40 $ 155 (a) Represents the Southern Company parent entity. (b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017 . (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million , respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million , respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018. 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 electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder. Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of the other subsidiaries' 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 and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2017 , Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants. A portion of the $8.1 billion unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016 . In addition, at December 31, 2017 , the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months . Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode. Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. 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 Outstanding Weighted Average Interest Rate (in millions) December 31, 2017: Commercial paper $ 1,832 1.8 % Short-term bank debt 607 2.3 % Total $ 2,439 1.9 % December 31, 2016: Commercial paper $ 1,909 1.1 % Short-term bank debt 123 1.7 % Total $ 2,032 1.1 % In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 , Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017 and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016 . Redeemable Preferred Stock of Subsidiaries At December 31, 2016 , each of the traditional electric operating companies had outstanding preferred and/or preference stock. During 2017, Alabama Power and Gulf Power each redeemed all of its outstanding preference stock and Georgia Power redeemed all of its outstanding preferred and 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 did 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 "Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity. The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable P |
ALABAMA POWER CO | |
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 outstanding as of December 31, 2017 and 2016 , 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 December 31, 2017 and 2016 , 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, 2017 , the Company had no securities due within one year. At December 31, 2016 , the Company had $561 million of senior notes and pollution control revenue bonds due within one year. Maturities through 2022 applicable to total long-term debt are as follows: $200 million in 2019 ; $250 million in 2020 ; $310 million in 2021 ; and $750 million in 2022 . There are no scheduled maturities in 2018 . Bank Term Loans At both December 31, 2017 and 2016 , the Company had $45 million of outstanding bank term loan agreements, which are reflected in the statements of capitalization as 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 calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. At December 31, 2017 , the Company was in compliance with its debt limits. Pollution Control Revenue Bonds Pollution control revenue bond 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. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2017. In August 2017, the Company repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project). The Company had $1.06 billion and $1.10 billion of tax-exempt pollution control revenue bond obligations outstanding at December 31, 2017 and 2016 , respectively, including pollution control revenue bonds classified as due within one year. Senior Notes In March 2017, the Company issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program. In November 2017, the Company issued $550 million aggregate principal amount of Series 2017B 3.70% Senior Notes due December 1, 2047. The proceeds were used for general corporate purposes, including the Company's continuous construction program . At December 31, 2017 and 2016 , the Company had $6.4 billion and $5.8 billion of senior notes outstanding, respectively, including senior notes classified as due within one year. At December 31, 2017 and 2016, the Company did not have any outstanding secured debt. Redeemable Preferred and Preference Stock The Company currently has preferred stock, Class A preferred stock, and common stock outstanding. The Company also has authorized preference stock, none of which is outstanding. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's 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 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. All series of the Company's preferred stock currently are subject to redemption at the option of the Company. The Class A preferred stock is subject to redemption on or after October 1, 2022, or following the occurrence of a rating agency event. 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 5.00% Class A Preferred Stock $25 10,000,000 Stated Capital (*) (*) Prior to October 1, 2022: $25.50 ; on or after October 1, 2022: Stated Capital In September 2017, the Company issued 10 million shares ( $250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital 25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ( $50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ( $150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ( $38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including the Company's continuous construction program. There were no changes for the year ended December 31, 2016 in redeemable preferred stock or preference stock of the Company. 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, 2017 , committed credit arrangements with banks were as follows: Expires Expires Within One Year 2018 2020 2022 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) $ 35 $ 500 $ 800 $ 1,335 $ 1,335 $ — $ 35 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 / 4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. Subject to applicable market conditions, the Company expects to renew or replace its bank credit agreements as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder. Most of the Company's 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 calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. At December 31, 2017 , 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 pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $854 million as of December 31, 2017 . In addition, at December 31, 2017, the Company had $120 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, 2017 , the Company had $3 million in short-term debt outstanding and none at December 31, 2016 . At December 31, 2017 , the Company had regulatory approval to have outstanding up to $2.0 billion of short-term borrowings. |
GEORGIA POWER CO | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Securities Due Within One Year A summary of scheduled maturities of securities due within one year at December 31 was as follows: 2017 2016 (in millions) Senior notes $ 750 $ 450 Capital leases 11 10 Other long-term debt 100 — Unamortized debt issuance expense (1 ) — Total $ 860 $ 460 Maturities through 2022 applicable to total long-term debt are as follows: $861 million in 2018 ; $513 million in 2019 ; $1.0 billion in 2020 ; $375 million in 2021 ; and $518 million in 2022 . Bank Term Loans In June 2017, the Company entered into three floating rate bank loans in aggregate principal amounts of $50 million , $150 million , and $100 million , with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, bearing interest based on one-month LIBOR. Also in June 2017, the Company borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by the Company and the bank from time to time and is payable on no less than 30 days ' demand by the bank. The proceeds from these bank loans were used to repay a portion of the Company's existing indebtedness and for working capital and other general corporate purposes, including the Company's continuous construction program. In August 2017, the Company repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, the Company amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018. In December 2017, the Company repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. At December 31, 2017 , the Company had a total of $250 million in bank term loans outstanding. Subsequent to December 31, 2017 , the Company repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively. At December 31, 2016 , the Company had no bank term loans outstanding. The outstanding bank loans as of December 31, 2017 had covenants that limited debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities. At December 31, 2017, the Company was in compliance with its debt limits. Senior Notes In March 2017, the Company issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program. In August 2017, the Company issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay the Company's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes. At December 31, 2017 and 2016 , the Company had $7.1 billion and $6.2 billion of senior notes outstanding, respectively, which included senior notes due within one year. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $2.8 billion at both December 31, 2017 and 2016 . As of December 31, 2017 , the Company's secured debt included borrowings of $2.6 billion guaranteed by the DOE and capital lease obligations of $154 million . As of December 31, 2016 , the Company's secured debt included borrowings of $2.6 billion guaranteed by the DOE and capital lease obligations of $169 million . See Note 7 and "DOE Loan Guarantee Borrowings" herein for additional information. Pollution Control Revenue Bonds Pollution control revenue bond 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 bond obligations outstanding at both December 31, 2017 and 2016 was $1.8 billion . In April 2017, the Company purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. In October 2017, the Company remarketed these bonds to the public. In August 2017, the Company purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. In October 2017, the Company remarketed these bonds to the public. Junior Subordinated Notes At December 31, 2017 , the Company had a total of $270 million of junior subordinated notes outstanding. At December 31, 2016 , the Company had no junior subordinated notes outstanding. In September 2017, the Company issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of the Company's preferred and preference stock. See "Outstanding Classes of Capital Stock" herein for additional information. 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 the Loan Guarantee Agreement in 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. On July 27, 2017, the Company entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to the Company's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses). Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, the Company will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) the Company's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements. Proceeds of advances made under the FFB Credit Facility are used to reimburse the Company for 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 . On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. 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. In addition to the conditions described above, 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, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. Upon satisfaction of all conditions described above, 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% . At both December 31, 2017 and 2016 , the Company had $2.6 billion of borrowings outstanding under the FFB Credit Facility. 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). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if the Company does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by the Company not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by the Company if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or the Company's ability to repay the outstanding borrowings under the FFB Credit Facility. 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. In addition, if the Company discontinues construction of Plant Vogtle Units 3 and 4, the Company would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by the Company under the Guarantee Settlement Agreement. The Company also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, 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, 2017 and 2016 , the Company had a capital lease asset for its corporate headquarters building of $61 million , with accumulated depreciation at December 31, 2017 and 2016 of $39 million and $33 million , respectively. At December 31, 2017 and 2016 , the capitalized lease obligation was $22 million and $28 million , respectively, with an annual interest rate of 7.9% . For ratemaking purposes, the Georgia PSC has allowed the lease payments in cost of service with no return on the capital lease asset. The difference between the depreciation and the lease payments allowed for ratemaking purposes is recovered as operating expenses as ordered by the Georgia PSC. The annual operating expense incurred for this capital lease was not material for any year presented. At December 31, 2017 and 2016 , the Company had capital lease assets related to two PPAs with Southern Power of $144 million and $149 million , respectively, with accumulated amortization at December 31, 2017 and 2016 of $29 million and $19 million , respectively. At December 31, 2017 and 2016 , the related capitalized lease obligations were $132 million and $141 million , respectively. The annual interest rates range from 10% to 12% for these two capital lease PPAs. For ratemaking purposes, the Georgia PSC has included the capital lease asset amortization in cost of service and the interest in the Company's cost of debt. See Note 1 under "Affiliate Transactions" and Note 7 under "Fuel and Purchased Power Agreements" for additional information. 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 common stock outstanding. In October 2017, the Company redeemed all 1.8 million shares ( $45 million aggregate liquidation amount) of its 6.125% Series Class A Preferred Stock and 2.25 million shares ( $225 million aggregate liquidation amount) of its 6.50% Series 2007A Preference Stock. No shares of preferred stock, Class A preferred stock, or preference stock were outstanding at December 31, 2017 . 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, 2017 , the Company had a $1.75 billion committed credit arrangement with banks, of which $1.73 billion was unused. In May 2017, the Company amended its multi-year credit arrangement which, among other things, extended the maturity date from 2020 to 2022. This bank credit arrangement requires payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1 / 4 of 1% for the Company. This bank credit arrangement contains a covenant that limits the Company's debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes certain hybrid securities. At December 31, 2017 , the Company was in compliance with the debt limit covenant. Subject to applicable market conditions, the Company expects to renew this bank credit arrangement, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder. A portion of the $1.73 billion unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2017 was $550 million as compared to $868 million at December 31, 2016 . In addition, at December 31, 2017 , the Company had $469 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangement described above. Commercial paper is included in notes payable in the balance sheets. Details of short-term borrowings outstanding were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017: Short-term bank debt $ 150 2.2 % December 31, 2016: Commercial paper $ 392 1.1 % |
GULF POWER CO | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Securities Due Within One Year At December 31, 2017 , the Company had no long-term debt due within one year . At December 31, 2016 , the Company had $87 million of long-term debt due within one year . Maturities through 2022 applicable to total long-term debt include $175 million in 2020 and $141 million in 2022. There are no scheduled maturities in 2018, 2019, or 2021. Bank Term Loans At December 31, 2016 , the Company had $100 million of bank term loans outstanding. In March 2017, the Company extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one -month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017. Senior Notes At December 31, 2017 and 2016 , the Company had a total of $990 million and $777 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 both December 31, 2017 and 2016 . In May 2017, the Company issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017, to repay outstanding commercial paper borrowings, to repay a $100 million short-term floating rate bank loan, and to redeem, in June 2017, all outstanding shares of preference stock. See "Bank Term Loans" and "Outstanding Classes of Capital Stock" herein for more information. Pollution Control Revenue Bonds Pollution control revenue bond 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 bond obligations outstanding at December 31, 2017 and 2016 was $309 million . 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, would 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, 2017 . The Company's preference stock would rank senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. No shares of preference stock were outstanding at December 31, 2017 . In June 2017, the Company redeemed 550,000 shares ( $55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ( $45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ( $50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock. In January 2017, the Company issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million . The proceeds were used for 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 aggregate outstanding principal amount of $41 million as of December 31, 2017 . 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, 2017 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2018 2019 2020 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $ 30 $ 25 $ 225 $ 280 $ 280 $ 45 $ — $ 20 $ 10 In November 2017, the Company amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020. 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. Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. 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, 2017 , the Company was in compliance with these covenants. Most of the $280 million of unused credit arrangements with banks provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2017 was approximately $82 million . In addition, at December 31, 2017 , the Company had $75 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months . 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 on the balance sheets. Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017: Commercial paper $ 45 2.0% December 31, 2016: Commercial paper $ 168 1.1% Short-term bank debt 100 1.5% Total $ 268 1.2% |
MISSISSIPPI POWER CO | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Going Concern The Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company. Specifically, the Company has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide the Company with loans and/or equity to fund the remaining indebtedness to mature and other cash needs over the next 12 months. As of December 31, 2017, the Company's current liabilities exceeded current assets by approximately $911 million primarily due to a $900 million unsecured term loan that matures on March 31, 2018. The Company expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. To fund the Company's capital needs over the next 12 months, the Company intends to utilize operating cash flows, external security issuances, lines of credit, bank term loans, equity contributions from Southern Company and, to the extent necessary, loans from Southern Company. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2017 and 2016 was as follows: 2017 2016 (in millions) Parent company loans $ — $ 551 Senior notes — 35 Bank term loans 900 — Revenue bonds (*) 90 40 Capitalized leases — 3 Unamortized debt issuance expense (1 ) — Outstanding at December 31 $ 989 $ 629 (*) Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. Maturities through 2022 applicable to total long-term debt are as follows: $900 million in 2018, $125 million in 2019, and $270 million in 2021. For long-term debt, other than revenue bonds, there are no scheduled maturities for 2020 and 2022. Parent Company Loans and Equity Contributions At December 31, 2016, the Company had $551 million of outstanding promissory notes to Southern Company. In February 2017, the Company amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan. In September 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" for additional information. At December 31, 2017, the Company had no outstanding promissory notes to Southern Company. Bank Term Loans In March 2017, the Company issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017. In June 2017, the Company used a portion of the proceeds from Southern Company equity contributions to prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018, and to repay $10 million of the outstanding principal amount of bank loans. See "Parent Company Loans and Equity Contributions" herein for more information. This unsecured term loan has a covenant that limits debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities. At December 31, 2017 , the Company was in compliance with its debt limit. In August 2017, the Company repaid a $12.5 million short-term bank note. At December 31, 2017 , the Company had a $900 million unsecured term loan outstanding, which was reflected in the statements of capitalization as securities due within one year. At December 31, 2016 , the Company had a $1.2 billion unsecured term loan outstanding, which was reflected in the statements of capitalization as long-term debt. Senior Notes At December 31, 2017 and 2016 , the Company had $755 million and $790 million of senior notes outstanding, respectively, which included senior notes due within one year . 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 million , reflecting a premium of $76 million . See "Assets Subject to Lien" 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 pollution control 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, 2017 and 2016 was $83 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 County energy facility and related facilities. The Company had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2017 and 2016 . Such amounts are reflected in the statements of capitalization as long-term debt. Capital Leases In 2013, the Company entered into an agreement to sell the air separation unit for the Kemper County energy facility 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 of $74 million at December 31, 2016. Following the suspension of the Kemper IGCC, the Company entered into an asset purchase and settlement agreement in December 2017 with the lessor, which terminated the capital lease obligation. There were no contingent rentals in the contract and a portion of the monthly payment specified in the agreement was 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 2017 were $7 million . See Note 3 under "Kemper County Energy facility" for additional information. 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. See "Plant Daniel Revenue Bonds" herein for additional information. On October 4, 2017, the Company executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in its co-generation assets, with a net book value of approximately $93 million , located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of the Company's credit rating to below investment grade by two of the three rating agencies. 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. Information for each outstanding series is in the table below: Preferred Stock Par Value/Stated Capital Per Share Shares Outstanding Redemption Price Per Share 4.40% Preferred Stock $ 100 8,867 $ 104.32 4.60% Preferred Stock $ 100 8,643 $ 107.00 4.72% Preferred Stock $ 100 16,700 $ 102.25 5.25% Preferred Stock (*) $ 100 300,000 $ 100.00 (*) There are 1,200,000 outstanding depositary shares, each representing one-fourth of a share of the 5.25% preferred 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, 2017 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2018 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $100 $100 $100 $— $— $— $100 In November 2017, the Company amended certain of its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018. Subject to applicable market conditions, the Company expects to renew its bank credit arrangements, as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. 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. A portion of the $100 million unused credit with banks is allocated to provide liquidity support to the Company's 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, 2017 was $40 million . In addition, at December 31, 2017, the Company had approximately $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode, subsequent to December 31, 2017 . At December 31, 2017 and 2016 , there was no commercial paper debt outstanding. At December 31, 2017 and 2016 , there was $4 million and $23 million , respectively, of short-term debt outstanding. |
SOUTHERN POWER CO | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Southern Power Company's senior notes, bank term loans, commercial paper, and Facility (as defined herein) are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Compan y. The Company's subsidiaries are not issuers, borrowers, or obligors, as applicable, under the senior notes, borrowings from financial institutions , commercial paper, or the Facility. The se nior notes, borrowings from financial institutions, commercial paper, and the Facility are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of the Company's subsidiaries. As of December 31, 2017 , the Company had no secured debt . Securities Due Within One Year At December 31, 2017 , the Company had $420 million in term loans and $350 million of senior notes due within one year. At December 31, 2016 , the Company had a $60 million term loan, $ 500 million of senior notes, and $1 million of long-term notes due within one year. Maturities of long-term debt for the next five years are as follows: December 31, 2017 (in millions) 2018 $ 770 2019 600 2020 825 2021 300 2022 (*) 677 (*) Represents euro-denominated debt at the U.S. dollar denominated hedge settlement amount. Senior Notes In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500 million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt. At December 31, 2017 and 2016 , the Company had $5.5 billion and $5.3 billion of senior notes outstanding, respectively, which included senior notes due within one year. Other Long-Term Notes In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes. At December 31, 2017 , outstanding term loans were included in securities due within one year. The outstanding term loans as of December 31, 2017 have a covenant that limits debt levels to 65% of total capitalization, as defined in the agreements. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the company to the extent such debt is non-recourse to the company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017 , the Company was in compliance with its debt limits. Bank Credit Arrangements Company Credit Facilities At December 31, 2017 , the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under the Facility to $750 million from $600 million . 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. As of December 31, 2016 , $78 million was used for letters of credit and $522 million remained unused. The Facility does not contain a material adverse change clause at the time of borrowing. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. The Company's subsidiaries are not parties to the Facility. The 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% . For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017 , the Company was in compliance with its debt limits. The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017 , $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. At December 31, 2016, the total amount available under this facility was $82 million . The Company's subsidiaries are not parties to this letter of credit facility. In addition, at both December 31, 2017 and 2016, the Company has $ 113 million of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets in the consolidated balance sheets. 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. The Company's subsidiaries are not parties to the commercial paper program. Commercial paper is included in notes payable in the consolidated balance sheets as noted below: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017 $ 105 2.0 % December 31, 2016 $ — N/A Subsidiary Project Credit Facilities In connection with the construction of solar facilities by RE Tranquillity LLC, RE Garland Holdings LLC, and RE Roserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity and Garland Project Credit Facilities were fully repaid on October 14, 2016 and December 29, 2016, respectively. The table below summarizes the Roserock Project Credit Facility as of December 31, 2016, which was extended to January 31, 2017 and fully repaid on January 17, 2017. Construction Loan Facility Bridge Loan Facility Total Loan Facility Loan Facility Undrawn Letter of Credit Facility Letter of Credit Facility Undrawn (in millions) December 31, 2016 $ 63 $ 180 $ 243 $ 34 $ 23 $ 16 The Project Credit Facilities had no amount outstanding at December 31, 2017 and $209 million outstanding with a weighted average interest rate of 2.1% as of December 31, 2016 . Assets Subject to Lien Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017 . See Note 11 for additional information. Roserock is in a litigation dispute with McCarthy regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. See Note 3 for additional information. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. |
SOUTHERN Co GAS | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING The Company's 100% -owned subsidiary, Southern Company Gas Capital, was established to provide for certain of the Company's ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital and the gas facility revenue bonds issued by Pivotal Utility Holdings. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs. Securities Due Within One Year The current portion of long-term debt is composed of the portion of its long-term debt due within the next 12 months. At December 31, 2017 , the Company had $157 million of senior notes due within one year, including the fair value adjustment attributable to the application of acquisition accounting. At December 31, 2016 , the Company had $22 million of medium-term notes due within one year. Long-Term Debt Long-term debt of the Company at December 31, 2017 and 2016 consisted of Series A, Series B, and Series C medium-term notes of Atlanta Gas Light; senior notes of Southern Company Gas Capital; first mortgage bonds of Nicor Gas; and gas facility revenue bonds of Pivotal Utility Holdings. Maturities through 2022 applicable to total long-term debt are as follows: $155 million in 2018 ; $350 million in 2019 ; $330 million in 2021 ; $93 million in 2022 ; and $4.6 billion thereafter. There are no material scheduled maturities in 2020. Medium-Term Notes In July 2017, Atlanta Gas Light repaid at maturity $22 million of medium-term notes. The amount of medium-term notes outstanding at December 31, 2017 and 2016 was $159 million and $181 million , respectively, including securities due within one year. Senior Notes In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes. The amount of senior notes outstanding at December 31, 2017 and 2016 was $4.2 billion and $3.7 billion , respectively, including securities due within one year. First Mortgage Bonds Nicor Gas had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016 , respectively. These bonds have been issued with maturities ranging from 2019 to 2057. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. Gas Facility Revenue Bonds Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from each issuance then are loaned to Pivotal Utility Holdings. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million . The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information. Parent Company Note On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million due July 31, 2018, bearing interest based on one-month LIBOR. Dividend Restrictions By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. The New Jersey BPU restricts the amount Elizabethtown Gas can dividend to its parent company to 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, the Company is prohibited from paying dividends to its parent company, Southern Company, if the Company's senior unsecured debt rating falls below investment grade. As of December 31, 2017 , the amount of subsidiary retained earnings restricted for dividend payment totaled $719 million . Bank Credit Arrangements Credit Facilities At December 31, 2017 , committed credit arrangements with banks were as follows: Company Expires 2022 Unused (in millions) Southern Company Gas Capital $ 1,400 $ 1,390 Nicor Gas 500 500 Total $ 1,900 $ 1,890 In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million , respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.4 billion and $500 million , respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of the Company and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if the Company or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017 , both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings. Commercial Paper Programs The Company maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas that consist of short-term, unsecured promissory notes. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of the Company's other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. Commercial paper is included in notes payable in the balance sheets. Details of commercial paper borrowings outstanding were as follows: Short-term Debt at the End of the Period Amount Weighted Average Interest Rate (in millions) December 31, 2017: Southern Company Gas Capital $ 1,243 1.73 % Nicor Gas 275 1.83 Total $ 1,518 1.75 % December 31, 2016: Southern Company Gas Capital $ 733 1.09 % Nicor Gas 524 0.95 Total $ 1,257 1.03 % |
Common Stock and Stock Compensa
Common Stock and Stock Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Class of Stock [Line Items] | |
Common stock | COMMON STOCK Stock Issued During 2017 , Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million . In addition, during the second and third quarters of 2017 , Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million , net of $1.1 million in fees and commissions. Shares Reserved At December 31, 2017 , a total of 71 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Outside Directors Stock Plan, the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below), and an at-the-market program. Of the total 71 million shares reserved, there were 13 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2017 . Stock-Based Compensation Stock-based compensation primarily in the form of performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017 , there were 5,112 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs. In conjunction with the Merger, stock-based compensation in the form of Southern Company restricted stock and performance share units was also granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan. Performance Share Units Performance share units granted to employees vest at the end of a three -year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three -year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common 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. The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three -year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. In determining the fair value of the TSR-based awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. 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 2017 2016 2015 Expected volatility 15.6% 15.0% 12.9% Expected term (in years) 3 3 3 Interest rate 1.4% 0.8% 1.0% Weighted average grant-date fair value $49.08 $45.06 $46.38 The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017 , 2016 , and 2015 was $49.21 , $48.87 , and $47.75 , respectively. Total unvested performance share units outstanding as of December 31, 2016 were 3.2 million . During 2017 , 1.2 million performance share units were granted and 1.5 million performance share units were vested or forfeited, resulting in 2.9 million unvested performance share units outstanding at December 31, 2017 . The number of shares to be issued for the three -year performance and vesting period ended December 31, 2017 will be determined in the first quarter 2018 . For the years ended December 31, 2017 , 2016 , and 2015 , total compensation cost for performance share units recognized in income was $74 million , $96 million , and $88 million , respectively, with the related tax benefit also recognized in income of $29 million , $37 million , and $34 million , respectively. As of December 31, 2017 , $30 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months . Restricted Stock Units Beginning in 2017 , stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three -year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period. The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three -year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one -, two -, or three -year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.25 . During 2017 , 0.6 million restricted stock units were granted and 0.1 million restricted stock units were vested or forfeited, resulting in 0.7 million unvested restricted stock units outstanding at December 31, 2017 , including previously issued restricted stock units related to other employee retention agreements. For the year ended December 31, 2017 , total compensation cost for restricted stock units recognized in income was $25 million with the related tax benefit also recognized in income of $10 million . As of December 31, 2017 , $8 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months . Stock Options In 2015, Southern Company discontinued the granting of stock options and all outstanding options have vested. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024. Southern Company's activity in the stock option program for 2017 is summarized below: Shares Subject to Option Weighted Average Exercise Price (in millions) Outstanding at December 31, 2016 24.6 $ 41.28 Exercised 6.0 40.03 Cancelled — 39.90 Outstanding and Exercisable at December 31, 2017 18.6 $ 41.68 As of December 31, 2017 , the weighted average remaining contractual term for the options outstanding and options exercisable was approximately five years and the aggregate intrinsic value for the options outstanding and options exercisable was $119 million . Total compensation cost for stock option awards and the related tax benefits recognized in income were immaterial for all years presented. The total intrinsic value of options exercised during the years ended December 31, 2017 , 2016 , and 2015 was $64 million , $120 million , and $48 million , respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $25 million , $46 million , and $19 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. 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, 2017 , 2016 , and 2015 was $239 million , $448 million , and $154 million , respectively. Southern Company Gas Restricted Stock Awards At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company's restricted stock units. Under the terms of the restricted stock awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three -year vesting schedule of the award being replaced. Southern Company issued 0.7 million restricted stock units with a grant-date fair value of $53.83 , based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration. For the years ended December 31, 2017 and 2016, total compensation cost for restricted stock units recognized in income was $8 million and $13 million , respectively, and the related tax benefit also recognized in income was $4 million for each year. As of December 31, 2017, $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months . Southern Company Gas Change in Control Awards Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares). The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance. For the years ended December 31, 2017 and 2016, total compensation cost for the change in control awards recognized in income was $12 million and $4 million , respectively. The related tax benefit also recognized in income was $6 million for the year ended December 31, 2017 and an immaterial amount for the year ended December 31, 2016. As of December 31, 2017, approximately $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months . Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted EPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted EPS were as follows: Average Common Stock Shares 2017 2016 2015 (in millions) As reported shares 1,000 951 910 Effect of options and performance share award units 8 7 4 Diluted shares 1,008 958 914 Prior to the adoption of ASU 2016-09 in 2016 , the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all "in the money" outstanding share based awards. Stock options and performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial in all years presented. Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2017 , consolidated retained earnings included $5.3 billion of undistributed retained earnings of the subsidiaries. |
ALABAMA POWER CO | |
Class of Stock [Line Items] | |
Stock compensation | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017 , there were 793 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs. Performance Share Units Performance share units granted to employees vest at the end of a three -year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three -year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three -year performance period without remeasurement. The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three -year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. For the years ended December 31, 2017 , 2016 , and 2015, employees of the Company were granted performance share units of 135,502 , 249,065 , and 214,709 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2017, 2016, and 2015, 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 $49.07 , $45.15 , and $46.42 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.21 , $48.86 , and $47.78 , respectively. For the years ended December 31, 2017 , 2016 , and 2015, total compensation cost for performance share units recognized in income was $9 million , $15 million , and $13 million , respectively, with the related tax benefit also recognized in income of $4 million , $6 million , and $5 million , respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017 , $2 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months . Restricted Stock Units Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three -year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period. The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three -year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one -, two -, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. For the year ended December 31, 2017 , employees of the Company were granted 58,001 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.21 . For the year ended December 31, 2017 , total compensation cost for restricted stock units recognized in income was $3 million with the related tax benefit also recognized in income of $1 million . As of December 31, 2017 , total unrecognized compensation cost related to restricted stock units was immaterial. Stock Options In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024. The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017 , all compensation cost related to stock option awards has been recognized. The total intrinsic value of options exercised during the years ended December 31, 2017 , 2016 , and 2015 was $12 million , $21 million , and $8 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $5 million , $8 million , and $3 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Prior to the adoption of ASU 2016-09 in 2016 , the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017 , the aggregate intrinsic value for the options outstanding and exercisable was $17 million . |
GEORGIA POWER CO | |
Class of Stock [Line Items] | |
Stock compensation | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017 , there were 895 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs. Performance Share Units Performance share units granted to employees vest at the end of a three -year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three -year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three -year performance period without remeasurement. The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three -year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. For the years ended December 31, 2017 , 2016 , and 2015 , employees of the Company were granted performance share units of 138,102 , 261,434 , and 236,804 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2017 , 2016 , and 2015 , 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 $49.27 , $45.17 , and $46.41 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017 , 2016 , and 2015 was $49.22 , $48.84 , and $47.78 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , total compensation cost for performance share units recognized in income was $10 million , $15 million , and $15 million , respectively, with the related tax benefit also recognized in income of $4 million , $6 million , and $6 million , respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017 , $3 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months . Restricted Stock Units Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three -year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period. The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three -year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one -, two -, or three -year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. For the year ended December 31, 2017, employees of the Company were granted 59,218 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.22 . For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $3 million with the related tax benefit also recognized in income of $1 million . As of December 31, 2017, $1 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months . Stock Options In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024. The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017 , all compensation cost related to stock option awards has been recognized. The total intrinsic value of options exercised during the years ended December 31, 2017 , 2016 , and 2015 was $13 million , $18 million , and $9 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $5 million , $7 million , and $4 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Prior to the adoption of ASU 2016-09 in 2016, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017 , the aggregate intrinsic value for the options outstanding and exercisable was $30 million . |
GULF POWER CO | |
Class of Stock [Line Items] | |
Stock compensation | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017 , there were 168 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs. Performance Share Units Performance share units granted to employees vest at the end of a three -year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three -year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three -year performance period without remeasurement. The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three -year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. For the years ended December 31, 2017 , 2016 , and 2015 , employees of the Company were granted performance share units of 28,423 , 57,333 , and 48,962 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2017 , 2016 , and 2015 , 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 $47.30 , $45.18 , and $46.38 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017 , 2016 , and 2015 was $49.18 , $48.83 , and $47.75 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , total compensation cost for performance share units recognized in income and the related tax benefit also recognized in income was immaterial. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017 , total unrecognized compensation cost related to performance share award units was immaterial. Restricted Stock Units Beginning in 2017 , stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three -year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period. The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three -year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. For the year ended December 31, 2017 , employees of the Company were granted 15,736 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $48.88 . For the year ended December 31, 2017 , total compensation cost and the related tax benefit for restricted stock units recognized in income was immaterial. As of December 31, 2017 , total unrecognized compensation cost related to restricted stock units was immaterial. Stock Options In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024. The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017 , all compensation cost related to stock option awards has been recognized. The total intrinsic value of options exercised during the years ended December 31, 2017 , 2016 , and 2015 was $2 million , $3 million , and $2 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises were immaterial for all years presented. Prior to the adoption of ASU 2016-09 in 2016 , the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017 , the aggregate intrinsic value for the options outstanding and exercisable was $3 million . |
MISSISSIPPI POWER CO | |
Class of Stock [Line Items] | |
Stock compensation | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017 , there were 180 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs. Performance Share Units Performance share units granted to employees vest at the end of a three -year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three -year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three -year performance period without remeasurement. The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three -year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. For the years ended December 31, 2017 , 2016 , and 2015 , employees of the Company were granted performance share units of 30,933 , 62,435 , and 53,909 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2017 , 2016 , and 2015 , 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 $49.24 , $45.17 , and $46.41 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.22 , $48.84 , and $47.77 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , total compensation cost for performance share units recognized in income was $2 million , $4 million , and $4 million , respectively, with the related tax benefit also recognized in income of $1 million , $1 million , and $2 million , respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017 , total unrecognized compensation cost related to performance share award units was immaterial. Restricted Stock Units Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three -year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period. The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three -year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. For the year ended December 31, 2017 , employees of the Company were granted 13,260 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.22 . For the year ended December 31, 2017 , total compensation cost for restricted stock units and the related tax benefit also recognized in income was immaterial. As of December 31, 2017 , total unrecognized compensation cost related to restricted stock units was immaterial. Stock Options In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024. The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017 , all compensation cost related to stock option awards has been recognized. The total intrinsic value of options exercised during the years ended December 31, 2017 , 2016 , and 2015 was $2 million , $4 million , and $3 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1 million , $2 million , and $1 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Prior to the adoption of ASU 2016-09 in 2016, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017 , the aggregate intrinsic value for the options outstanding and exercisable was $4 million . |
SOUTHERN Co GAS | |
Class of Stock [Line Items] | |
Stock compensation | STOCK COMPENSATION Successor Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to certain levels of management within the Company. In 2017 , stock-based compensation granted to employees includes performance share units and restricted stock units. In 2016 , in conjunction with the Merger, stock-based compensation was granted to certain executives in the form of Southern Company restricted stock and performance share units. As of December 31, 2017 , there were 327 current and former employees participating in the performance share unit and restricted stock unit programs. Performance Share Units Performance share units granted to employees vest at the end of a three -year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common 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. The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period. For the year ended December 31, 2017 , employees of the Company were granted 0.3 million performance share units. The weighted average grant-date fair value of TSR-based performance share units granted during 2017 , 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 $49.27 . The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017 was $49.22 . For the year ended December 31, 2017 , total compensation cost for performance share units recognized in income was $8 million with the related tax benefit also recognized in income of $3 million . The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017 , $6 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months. Restricted Stock Units Stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three -year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period. The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three -year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one -, two -, or three -year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. For the year ended December 31, 2017 , employees of the Company were granted 0.1 million restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.23 . For the year ended December 31, 2017 , total compensation cost for restricted stock units recognized in income was $4 million with the related tax benefit also recognized in income of $2 million . The compensation cost related to the grant of Southern Company restricted stock units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017 , $1 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months. Merger Stock Compensation At the effective time of the Merger, each share of Southern Company Gas common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the Merger: • Southern Company Gas' outstanding restricted stock units, restricted stock awards, and non-employee director stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share; • Southern Company Gas' outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options; and • each outstanding award of a performance share unit was converted into an award of Southern Company's restricted stock units (restricted stock awards). In conjunction with the Merger, stock-based compensation, in the form of Southern Company restricted stock and performance share units, was granted to certain executives of the Company through the Southern Company Omnibus Incentive Compensation Plan. Southern Company Restricted Stock Awards Under the terms of the restricted stock awards, the employees received a specified number of restricted stock units that vest when the employees have satisfied the requisite service period(s) at which time the employee receives Southern Company common stock. The terms of the award require the employee to be continuously employed through the original three -year vesting schedule of the award being replaced. For the successor period ended December 31, 2016 , employees of the Company were granted 0.7 million restricted stock units. The grant-date fair value of the restricted stock units granted was $53.83 , based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration. The remaining fair value of $12 million is being recognized as compensation expense on a straight-line basis over the remaining vesting period. The compensation cost related to the grant of restricted stock 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. For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 , total compensation cost for restricted stock units recognized in income was $8 million and $13 million , respectively, with the related tax benefit also recognized in income of $4 million and $4 million , respectively. As of December 31, 2017 , $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months. See "Performance Share Unit Awards" herein for additional information. Change in Control Awards Southern Company awarded performance share units to certain employees remaining with the Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change-in-control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change-in-control benefit will vest and be issued one-third each year as long as the employee remains in service with the Company, or any of its affiliates, at each vest date. In addition to the change-in-control benefit, Southern Company common stock could be issued to the employees at the end of a performance period with the number of shares issued ranging from 0% to 100% of the target number of performance share units granted, based on achievement of certain Southern Company common stock price metrics, as well as performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares). The change-in-control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change-in-control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance. For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 , total compensation cost for the change-in-control awards recognized in income was $12 million and $4 million , respectively, with $6 million and less than $1 million , respectively, of related tax benefit recognized in income. The compensation cost related to the grant of Southern Company change-in-control benefit and achievement shares to the Company's employees are recognized in the Company's financial statements with a corresponding credit to a liability or equity, representing a capital contribution from Southern Company, respectively. As of December 31, 2017 , $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months . Predecessor For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , the employees of Southern Company Gas and subsidiaries participated in the AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated. The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provided for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards, and other stock-based awards to officers and key employees. Effective July 1, 2016, all Southern Company Gas shares of stock were canceled and/or converted as a result of the Merger. No further grants will be made from the Long-Term Incentive Plan (1999) or the AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated. For the predecessor periods, the Company recognized stock-based compensation expense for its stock-based awards over the requisite service period based on the estimated fair value at the date of grant for its stock-based awards using the modified prospective method. These stock awards included: stock options, stock and restricted stock awards, and performance units (restricted stock units, performance share units, and performance cash units). Performance-based stock awards and performance units contained market and performance conditions. Stock options, restricted stock awards, and performance units also contained a service condition. The Company estimated forfeitures over the requisite service period when recognizing compensation expense. These estimates were adjusted to the extent that actual forfeitures differ, or were expected to materially differ, from such estimates. Excess tax benefits were reported as a financing cash inflow. The difference between the proceeds from the exercise of the Company's stock-based awards and the par value of the stock was recorded within additional paid-in capital. Southern Company Gas granted stock awards with a grant price that was equal to the fair market value on the date of the grant. Fair market value was defined under the terms of the applicable plans as the closing price per share of Southern Company Gas' common stock on the grant date. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , total compensation cost for cash and stock-based awards recognized in income was $24 million and $40 million , respectively, with related tax benefits also recognized in income, which were immaterial. Incentive and Nonqualified Stock Options The stock options that the Company granted prior to the Merger had a three -year vesting period and expired ten years after the date of grant. The exercise price for stock options granted equaled the stock price of Southern Company Gas common stock on the date of grant. Participants realized value from option grants only to the extent that the fair market value of the Company's common stock on the date of exercise of the option exceeded the fair market value of the common stock on the date of the grant. No stock options have been issued under the plan since 2009. The Company measured compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. For the predecessor year ended December 31, 2015 , the Company had no unrecognized compensation costs related to stock options. For the predecessor period ended June 30, 2016 and the year ended December 31, 2015 , cash received from stock option exercises and the related income tax benefits were immaterial. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , the total intrinsic value of options exercised was $3 million , and $13 million , respectively. Effective July 1, 2016, all of the Company's outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options. Restricted Stock Units A restricted stock unit is an award that represents the opportunity to receive a specified number of shares of the Company's common stock, subject to the achievement of certain pre-established performance criteria. For the predecessor period of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , the Company granted 25,166 and 47,546 , respectively, of restricted stock units (including dividends) to certain employees. At the effective time of the Merger, all restricted stock units outstanding were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share. Performance Share Unit Awards A performance share unit award represented the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , the Company granted performance share unit awards to certain officers. The Company's 2016 and 2015 performance share units had two performance measures. One measure, which accounted for 75% , related to the Company's total shareholder return relative to a group of peer companies. The second measure, which accounted for 25% , related to the Company's earnings per share, excluding wholesale gas services, over the three -year performance period. At the effective time of the Merger, each outstanding performance share unit was converted into an award of Southern Company's restricted stock units. The conversion ratio was the product of (i) the greater of (a) 125% of the number of units underlying such award based on target level achievement of all relevant performance goals and (b) the number of units underlying such award based on the actual level of achievement of all relevant performance goals against target and (ii) an exchange ratio based on the Merger consideration of $66 per share as compared to the volume-weighted average price per share of Southern Company common stock. The resulting Southern Company restricted stock units will follow the vesting schedule and payment terms, and otherwise be issued on similar terms and conditions, as were applicable to such pre-Merger performance share unit awards, subject to certain exceptions. See "Southern Company Restricted Stock Awards" for additional information. Stock and Restricted Stock Awards The compensation cost of both stock awards and restricted stock awards was equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions were used to value the awards. The Company referred to restricted stock as an award of Company common stock subject to time-based vesting or achievement of performance measures. Prior to vesting, restricted stock awards were subject to certain transfer restrictions and forfeiture upon termination of employment. Restricted Stock Awards — Employees Total unvested restricted stock awards outstanding as of December 31, 2015 totaled 0.4 million . During 2016, 0.3 million restricted stock awards were granted, 0.7 million restricted stock awards were vested or forfeited. At the effective time of the Merger, Southern Company Gas' outstanding restricted stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share. |
Nuclear Insurance
Nuclear Insurance | 12 Months Ended |
Dec. 31, 2017 | |
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 $13.4 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 $450 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 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 and policies 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. 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 Vogtle 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 maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2017 under the NEIL policies would be $55 million and $81 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 applicable 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 CO | |
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 $13.4 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $450 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 and policies 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. 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 maximum annual assessments for the Company as of December 31, 2017 under the NEIL policies would be $55 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 CO | |
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 $13.4 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 $450 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 and policies 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. The Company purchases limits based on the projected full cost of replacement power, subject to ownership limitations, and has elected a 12-week deductible waiting period for each facility. 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 Vogtle 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 maximum annual assessments for the Company as of December 31, 2017 under the NEIL policies would be $81 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, 2017 | |
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, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 331 $ 239 $ — $ — $ 570 Interest rate derivatives — 1 — — 1 Foreign currency derivatives — 129 — — 129 Nuclear decommissioning trusts: (c) Domestic equity 690 82 — — 772 Foreign equity 62 224 — — 286 U.S. Treasury and government agency securities — 251 — — 251 Municipal bonds — 68 — — 68 Corporate bonds 21 315 — — 336 Mortgage and asset backed securities — 57 — — 57 Private equity — — — 29 29 Other 19 12 — — 31 Cash equivalents 1,455 — — — 1,455 Other investments 9 — 1 — 10 Total $ 2,587 $ 1,378 $ 1 $ 29 $ 3,995 Liabilities: Energy-related derivatives (a)(b) $ 480 $ 253 $ — $ — $ 733 Interest rate derivatives — 38 — — 38 Foreign currency derivatives — 23 — — 23 Contingent consideration — — 22 — 22 Total $ 480 $ 314 $ 22 $ — $ 816 (a) Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives exclude cash collateral of $193 million . (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under " Nuclear Decommissioning " for additional information. As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 338 $ 333 $ — $ — $ 671 Interest rate derivatives — 14 — — 14 Nuclear decommissioning trusts: (c) Domestic equity 589 73 — — 662 Foreign equity 48 168 — — 216 U.S. Treasury and government agency securities — 92 — — 92 Municipal bonds — 73 — — 73 Corporate bonds 22 310 — — 332 Mortgage and asset backed securities — 183 — — 183 Private equity — — — 20 20 Other 11 15 — — 26 Cash equivalents 1,172 — — — 1,172 Other investments 9 — 1 — 10 Total $ 2,189 $ 1,261 $ 1 $ 20 $ 3,471 Liabilities: Energy-related derivatives (a)(b) $ 345 $ 285 $ — $ — $ 630 Interest rate derivatives — 29 — — 29 Foreign currency derivatives — 58 — — 58 Contingent consideration — — 18 — 18 Total $ 345 $ 372 $ 18 $ — $ 735 (a) Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives exclude cash collateral of $62 million . (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under " Nuclear Decommissioning " for additional information. Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded and 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. 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' judgments, are also obtained when available. See Note 1 under " Nuclear Decommissioning " for additional information. Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial. "Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions. As of December 31, 2017 and 2016 , the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows: Fair Unfunded Redemption Redemption (in millions) As of December 31, 2017 $ 29 $ 21 Not Applicable Not Applicable As of December 31, 2016 $ 20 $ 25 Not Applicable Not Applicable Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years . As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 48,151 $ 51,348 2016 $ 45,080 $ 46,286 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 available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas. |
ALABAMA POWER CO | |
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, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 4 $ — $ — $ 4 Nuclear decommissioning trusts: (*) Domestic equity 442 81 — — 523 Foreign equity 62 59 — — 121 U.S. Treasury and government agency securities — 24 — — 24 Corporate bonds 21 160 — — 181 Mortgage and asset backed securities — 18 — — 18 Private equity — — — 29 29 Other 6 — — — 6 Cash equivalents 349 — — — 349 Total $ 880 $ 346 $ — $ 29 $ 1,255 Liabilities: Energy-related derivatives $ — $ 10 $ — $ — $ 10 (*) 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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 20 $ — $ — $ 20 Nuclear decommissioning trusts: (*) Domestic equity 385 72 — — 457 Foreign equity 48 47 — — 95 U.S. Treasury and government agency securities — 21 — — 21 Corporate bonds 22 146 — — 168 Mortgage and asset backed securities — 19 — — 19 Private equity — — — 20 20 Other — 10 — — 10 Cash equivalents 262 — — — 262 Total $ 717 $ 335 $ — $ 20 $ 1,072 Liabilities: Energy-related derivatives $ — $ 9 $ — $ — $ 9 (*) 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. 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. 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. See Note 1 under "Nuclear Decommissioning" for additional information. 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' judgments, are also obtained when available. As of December 31, 2017 and 2016 , the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period (in millions) As of December 31, 2017 $ 29 $ 21 Not Applicable Not Applicable As of December 31, 2016 $ 20 $ 25 Not Applicable Not Applicable Private equity funds include a fund-of-funds that invests in high quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations of these investments are expected to occur at various times over the next 10 years . As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 7,625 $ 8,305 2016 $ 7,092 $ 7,544 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 available to the Company. |
GEORGIA POWER CO | |
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, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 6 $ — $ 6 Nuclear decommissioning trusts: (*) Domestic equity 248 1 — 249 Foreign equity — 166 — 166 U.S. Treasury and government agency securities — 227 — 227 Municipal bonds — 68 — 68 Corporate bonds — 155 — 155 Mortgage and asset backed securities — 40 — 40 Other 12 12 — 24 Cash equivalents 690 — — 690 Total $ 950 $ 675 $ — $ 1,625 Liabilities: Energy-related derivatives $ — $ 19 $ — $ 19 Interest rate derivatives — 5 — 5 Total $ — $ 24 $ — $ 24 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 44 $ — $ 44 Interest rate derivatives — 2 — 2 Nuclear decommissioning trusts: (*) Domestic equity 204 1 — 205 Foreign equity — 121 — 121 U.S. Treasury and government agency securities — 71 — 71 Municipal bonds — 73 — 73 Corporate bonds — 164 — 164 Mortgage and asset backed securities — 164 — 164 Other 11 5 — 16 Total $ 215 $ 645 $ — $ 860 Liabilities: Energy-related derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 3 — 3 Total $ — $ 11 $ — $ 11 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. 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' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 11,777 $ 12,531 2016 $ 10,516 $ 11,034 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 available to the Company. |
GULF POWER CO | |
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, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 21 $ — $ — $ 21 Liabilities: Energy-related derivatives $ — $ 21 $ — $ 21 As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 5 $ — $ 5 Cash equivalents 20 — — 20 Total $ 20 $ 5 $ — $ 25 Liabilities: Energy-related derivatives $ — $ 29 $ — $ 29 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 10 for additional information on how these derivatives are used. As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2017 $ 1,285 $ 1,334 2016 $ 1,074 $ 1,097 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 available to the Company. |
MISSISSIPPI POWER CO | |
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, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 2 $ — $ 2 Interest rate derivatives — 1 — 1 Cash equivalents 224 — — 224 Total $ 224 $ 3 $ — $ 227 Liabilities: Energy-related derivatives $ — $ 9 $ — $ 9 As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 3 $ — $ 3 Interest rate derivatives — 3 — 3 Cash equivalents 206 — — 206 Total $ 206 $ 6 $ — $ 212 Liabilities: Energy-related derivatives $ — $ 10 $ — $ 10 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, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2017 $ 2,086 $ 2,076 2016 $ 2,979 $ 2,922 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 CO | |
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, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 3 $ — $ 3 Foreign currency derivatives — 129 — 129 Cash equivalents 21 — — 21 Total $ 21 $ 132 $ — $ 153 Liabilities: Energy-related derivatives $ — $ 13 $ — $ 13 Foreign currency derivatives — 23 — 23 Contingent consideration — — 22 22 Total $ — $ 36 $ 22 $ 58 As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 21 $ — $ 21 Interest rate derivatives — 1 — 1 Cash equivalents 628 — — 628 Total $ 628 $ 22 $ — $ 650 Liabilities: Energy-related derivatives $ — $ 5 $ — $ 5 Foreign currency derivatives — 58 — 58 Contingent consideration — — 18 18 Total $ — $ 63 $ 18 $ 81 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 9 for additional information on how these derivatives are used. The Company has contingent payment obligations related to certain acquisitions whereby the Company is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial. As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 5,841 $ 6,079 2016 $ 5,628 $ 5,691 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 available to the Company. |
SOUTHERN Co GAS | |
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. See Note 1 under "Fair Value Measurements" for additional information on the fair value hierarchy. As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using As of December 31, 2017: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 331 $ 223 $ — $ — $ 554 Liabilities: Energy-related derivatives (a)(b) $ 479 $ 181 $ — $ — $ 660 (a) Energy-related derivatives excludes $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $193 million . As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using As of December 31, 2016: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 338 $ 239 $ — $ — $ 577 Liabilities: Energy-related derivatives (a)(b) $ 345 $ 224 $ — $ — $ 569 (a) Energy-related derivatives excludes $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $62 million . Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded financial products for natural gas, 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, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard OTC products that are valued using observable market data and assumptions commonly used by market participants. See Note 10 for additional information on how these derivatives are used. Debt The Company's long-term debt is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. The Company amortizes the fair value adjustments over the lives of the respective bonds. The following table presents the carrying amount and fair value of the Company's long-term debt as of December 31: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 6,048 $ 6,471 2016 $ 5,281 $ 5,491 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 available to the Company. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2017 | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate 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. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, 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 net 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. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under " Financial Instruments " for additional information. Energy-Related Derivatives Southern Company and certain subsidiaries enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, adversely affect results of operations. Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income. Energy-related derivative contracts are accounted for under one of three methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and natural gas distribution utilities' 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) 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 and natural gas industries. 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 621 million mmBtu for the Southern Company system, with the longest hedge date of 2021 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 2026 for derivatives not designated as hedges. In addition to the volumes discussed above, the traditional electric 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 32 million mmBtu. The estimated pre-tax gains (losses) related to energy-related derivatives that will be reclassified from accumulated OCI to earnings for the 12-month period ending December 31, 2018 total $(11) million 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. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. At December 31, 2017 , the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 900 1-month LIBOR 0.79% March 2018 $ 1 Fair Value Hedges of Existing Debt 250 5.40% 3-month LIBOR + 4.02% June 2018 — 500 1.95% 3-month LIBOR + 0.76% December 2018 (3 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 (1 ) 300 2.75% 3-month LIBOR + 0.92% June 2020 (2 ) 1,500 2.35% 1-month LIBOR + 0.87% July 2021 (31 ) Total $ 3,650 $ (36 ) The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12 -month period ending December 31, 2018 total $(20) million . Deferred gains and losses are expected to be amortized into earnings through 2046 . Foreign Currency Derivatives Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to 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 that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2017 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ 55 564 3.78% 500 1.85% June 2026 51 Total $ 1,241 € 1,100 $ 106 The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12 -month period ending December 31, 2018 total $(23) million . Derivative Financial Statement Presentation and Amounts Southern Company and its subsidiaries enter into derivative contracts that 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. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2017 and 2016 , the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 10 $ 43 $ 73 $ 27 Other deferred charges and assets/Other deferred credits and liabilities 7 24 25 33 Total derivatives designated as hedging instruments for regulatory purposes $ 17 $ 67 $ 98 $ 60 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Other current liabilities $ 3 $ 14 $ 23 $ 7 Interest rate derivatives: Other current assets/Other current liabilities 1 4 12 1 Other deferred charges and assets/Other deferred credits and liabilities — 34 1 28 Foreign currency derivatives: Other current assets/Other current liabilities — 23 — 25 Other deferred charges and assets/Other deferred credits and liabilities 129 — — 33 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 133 $ 75 $ 36 $ 94 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Other current liabilities $ 380 $ 437 $ 489 $ 483 Other deferred charges and assets/Other deferred credits and liabilities 170 215 66 81 Interest rate derivatives: Other current assets/Other current liabilities — — 1 — Total derivatives not designated as hedging instruments $ 550 $ 652 $ 556 $ 564 Gross amounts recognized $ 700 $ 794 $ 690 $ 718 Gross amounts offset (a) $ (405 ) $ (598 ) $ (462 ) $ (524 ) Net amounts recognized in the Balance Sheets (b) $ 295 $ 196 $ 228 $ 194 (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016 , respectively. (b) Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017. At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (34 ) $ (16 ) Other regulatory liabilities, current $ 7 $ 56 Other regulatory assets, deferred (18 ) (19 ) Other regulatory liabilities, deferred 1 12 Total energy-related derivative gains (losses) (*) $ (52 ) $ (35 ) $ 8 $ 68 (*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Amount Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Energy-related derivatives $ (47 ) $ 18 $ — Depreciation and amortization $ (16 ) $ 2 $ — Cost of natural gas (2 ) (1 ) — Interest rate derivatives (2 ) (180 ) (22 ) Interest expense, net of amounts capitalized (21 ) (18 ) (9 ) Foreign currency derivatives 140 (58 ) — Interest expense, net of amounts capitalized (23 ) (13 ) — Other income (expense), net (*) 160 (82 ) — Total $ 91 $ (220 ) $ (22 ) $ 98 $ (112 ) $ (9 ) (*) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record euro-denominated notes. There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows: Derivatives in Fair Value Hedging Relationships Gain (Loss) Derivative Category Statements of Income Location 2017 2016 2015 (in millions) Interest rate derivatives: Interest expense, net of amounts capitalized $ (22 ) $ (21 ) $ 2 For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt. For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Derivatives Not Designated as Hedging Instruments Unrealized Gain (Loss) Recognized in Income Amount Derivative Category Statements of Income Location 2017 2016 2015 (in millions) Energy-related derivatives Wholesale electric revenues $ (4 ) $ 2 $ (5 ) Fuel — — 3 Natural gas revenues (*) (80 ) 33 — Cost of natural gas (2 ) 3 — Total $ (86 ) $ 38 $ (2 ) (*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial. 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, 2017 , the Company had no collateral posted with derivative counterparties to satisfy these arrangements. At December 31, 2017 , the fair value of energy-related and interest rate derivative liabilities with contingent features was $15 million and $7 million , respectively. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $14 million and $7 million for energy-related and interest rate derivative contracts, respectively. 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 Southern Company system maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017 , cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company may be required to deposit cash into these accounts. At December 31, 2017 , cash collateral held on deposit in broker margin accounts was $193 million . Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern 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. Southern Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's exposure to counterparty credit risk. Southern Company may require counterparties to pledge additional collateral when deemed necessary. In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings. Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
ALABAMA POWER CO | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, including 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 net 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 energy-related commodity prices. 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. Energy-related derivative contracts are accounted for under 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 energy 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 69 million mmBtu for the Company, with the longest hedge date of 2020 over which it is hedging its exposure to the variability in future cash flows for forecasted transactions. 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 5 million mmBtu. 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, 2017 , there were no interest rate derivatives outstanding. The estimated pre-tax losses related to interest rate derivatives that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2018 are $6 million . The Company has deferred gains and losses that are expected to be amortized into earnings through 2035. Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2017 and 2016 , the fair value of energy-related derivatives was reflected on the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 2 $ 6 $ 13 $ 5 Other deferred charges and assets/Other deferred credits and liabilities 2 4 7 4 Total derivatives designated as hedging instruments for regulatory purposes $ 4 $ 10 $ 20 $ 9 Gross amounts recognized $ 4 $ 10 $ 20 $ 9 Gross amounts offset $ (4 ) $ (4 ) $ (8 ) $ (8 ) Net amounts recognized in the Balance Sheets $ — $ 6 $ 12 $ 1 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2017 and 2016 . At December 31, 2017 and 2016 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (4 ) $ (1 ) Other regulatory liabilities, current $ 1 $ 8 Other regulatory assets, deferred (3 ) — Other regulatory liabilities, deferred — 4 Total energy-related derivative gains (losses) $ (7 ) $ (1 ) $ 1 $ 12 For the years ended December 31, 2017 , 2016 , and 2015 , 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 OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Interest rate derivatives $ — $ (3 ) $ (7 ) Interest expense, net of amounts capitalized $ (6 ) $ (6 ) $ (3 ) 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 not material for any year 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, 2017 , the fair value of derivative liabilities with contingent features was $1 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 $12 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 maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017 , the Company's collateral posted in these accounts was not material. 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 CO | |
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 net 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 energy-related commodity prices. The Company manages a fuel-hedging program through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. At December 31, 2017 and 2016 , substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Effective January 1, 2016, the Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48 -month time horizon. Energy-related derivative contracts are accounted for under 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 163 million mmBtu, all of which expire by 2021 , 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 10 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. At December 31, 2017 , there were no cash flow hedges outstanding. 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, 2017 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Fair Value Hedges of Existing Debt $ 250 5.40% 3-month LIBOR + 4.02% June 2018 $ — 500 1.95% 3-month LIBOR + 0.76% December 2018 (3 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 (1 ) Total $ 950 $ (4 ) The estimated pre-tax gains (losses) related to interest rate derivatives that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2018 total $(4) million . Deferred gains and losses related to interest rate derivative settlements of cash flow hedges are expected to be amortized into earnings through 2037 . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2017 and 2016 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 2 $ (9 ) $ 30 $ 1 Other deferred charges and assets/Other deferred credits and liabilities 4 (10 ) 14 7 Total derivatives designated as hedging instruments for regulatory purposes $ 6 $ (19 ) $ 44 $ 8 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ — $ (4 ) $ 2 $ — Other deferred charges and assets/Other deferred credits and liabilities — (1 ) — 3 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ — $ (5 ) $ 2 $ 3 Gross amounts recognized $ 6 $ (24 ) $ 46 $ 11 Gross amounts offset $ (6 ) $ 6 $ (8 ) $ (8 ) Net amounts recognized in the Balance Sheets $ — $ (18 ) $ 38 $ 3 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2017 and 2016 . At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (7 ) $ — Other regulatory liabilities, current $ — $ 29 Other regulatory assets, deferred (6 ) — Other deferred credits and liabilities — 7 Total energy-related derivative gains (losses) $ (13 ) $ — $ — $ 36 For the years ended December 31, 2017 , 2016 , and 2015 , 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 Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Interest rate derivatives $ 1 $ — $ (15 ) Interest expense, net of amounts capitalized $ (4 ) $ (4 ) $ (3 ) For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were 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 statements of income were offset by changes to the carrying value of long-term debt. The gains and losses related to interest rate derivative settlements of fair value hedges are recorded directly to earnings. There was no 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, 2017 , the Company had no collateral posted with derivative counterparties to satisfy these arrangements. At December 31, 2017 , the fair value of derivative liabilities with contingent features was $2 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 $12 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 CO | |
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 net 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 energy-related commodity prices. 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. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. In connection with the 2017 Rate Case Settlement Agreement, the Florida PSC extended the moratorium on the Company's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. Energy-related derivative contracts are accounted for under 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 fuel 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) 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 22 million mmBtu for the Company, with the longest hedge date of 2020 over which it is hedging its exposure to the variability in future cash flows for forecasted transactions. 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 3 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. 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, 2017 , there were no interest rate derivatives outstanding. The estimated pre-tax losses related to interest rate derivatives that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2018 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2026 . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that 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. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2017 and 2016 , the fair value of energy-related derivatives was reflected on the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ — $ 14 $ 4 $ 12 Other deferred charges and assets/Other deferred credits and liabilities — 7 1 17 Total derivatives designated as hedging instruments for regulatory purposes $ — $ 21 $ 5 $ 29 Gross amounts recognized $ — $ 21 $ 5 $ 29 Gross amounts offset $ — $ — $ (4 ) $ (4 ) Net amounts recognized on the Balance Sheets $ — $ 21 $ 1 $ 25 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2017 and 2016 . At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (14 ) $ (9 ) Other regulatory liabilities, current $ — $ 1 Other regulatory assets, deferred (7 ) (16 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (21 ) $ (25 ) $ — $ 1 (*) The unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheets. For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were immaterial and there was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2017 , 2016 , and 2015 , 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, 2017 , the Company had no collateral posted with its derivative counterparties to satisfy these arrangements. At December 31, 2017 , the fair value of derivative liabilities with contingent features was immaterial. 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 $12 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 CO | |
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 net 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 energy-related commodity prices. 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. Energy-related derivative contracts are accounted for under one of the following 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. • 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 53 million mmBtu for the Company, with the longest hedge date of 2021 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions. 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 4 million mmBtu. 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, 2017 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 900 1-month LIBOR 0.79% March 2018 $ 1 The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2018 are $0.5 million . The Company has deferred gains and losses that are expected to be amortized into earnings through 2022 . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that 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. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with counterparties. At December 31, 2017 and 2016 , the fair value of energy-related derivatives and interest rate derivatives was reflected on the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 1 $ 6 $ 2 $ 6 Other deferred charges and assets/Other deferred credits and liabilities 1 3 2 5 Total derivatives designated as hedging instruments for regulatory purposes $ 2 $ 9 $ 4 $ 11 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ 1 $ — $ 2 $ — Other deferred charges and assets/Other deferred credits and liabilities — — 1 — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 1 $ — $ 3 $ — Gross amounts recognized $ 3 $ 9 $ 7 $ 11 Gross amounts offset $ (2 ) $ (2 ) $ (3 ) $ (3 ) Net amounts recognized in the Balance Sheets $ 1 $ 7 $ 4 $ 8 Energy-related derivatives not designated as hedging instruments were immaterial for 2017 and 2016 . At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (5 ) $ (5 ) Other current liabilities $ — $ 1 Other regulatory assets, deferred (2 ) (3 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (7 ) $ (8 ) $ — $ 1 For all years presented, 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, 2017, 2016, and 2015, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were immaterial. 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, 2017 , the Company had no collateral posted with its derivative counterparties. At December 31, 2017 , the fair value of derivative liabilities with contingent features was $1 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 $12 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 CO | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk, and occasionally foreign currency exchange 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 consolidated balance sheets as either assets or liabilities and are presented on a net basis. See Note 8 for additional fair value information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. The Company has limited exposure to market volatility in energy-related commodity prices 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. Energy-related derivative contracts are accounted for under 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 consolidated 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 consolidated 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 14 million mmBtu, all of which expire in 2018 . At December 31, 2017 , the net volume of energy-related derivative contracts for power positions was 3 million MWHs, all of which expire in 2018 . In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 10 million mmBtu. For cash flow hedges, gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12 -month period ending December 31, 2018 is $(7) million . 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. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred. At December 31, 2017 , the Company did not have any interest rate derivatives outstanding and does not have any deferred gains and losses in AOCI related to cash flow hedges that would be reclassified from AOCI to interest expense. Foreign Currency Derivatives The Company may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to 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 that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2017 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ 55 564 3.78% 500 1.85% June 2026 51 Total $ 1,241 € 1,100 $ 106 The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12 -month period ending December 31, 2018 total $(23) million . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Fair value amounts of derivative assets and liabilities on the consolidated balance sheets are presented net to the extent that there are netting arrangements or similar agreements with counterparties. At December 31, 2017 and 2016 , the fair value of energy-related, interest rate, and foreign currency derivatives reflected in the consolidated balance sheets is as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Other current liabilities $ 3 $ 11 $ 18 $ 4 Foreign currency derivatives: Other current assets/Other current liabilities — 23 — 25 Other deferred charges and assets/Other deferred credits and liabilities 129 — — 33 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 132 $ 34 $ 18 $ 62 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Other current liabilities $ — $ 2 $ 3 $ 1 Interest rate derivatives: Other current assets/Other current liabilities — — 1 — Total derivatives not designated as hedging instruments $ — $ 2 $ 4 $ 1 Gross amounts of recognized assets and liabilities $ 132 $ 36 $ 22 $ 63 Gross amounts offset $ (3 ) $ (3 ) $ (5 ) $ (5 ) Net amounts of assets and liabilities $ 129 $ 33 $ 17 $ 58 For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related, interest rate, and foreign currency derivatives designated as cash flow hedging instruments on the consolidated statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Energy-related derivatives $ (38 ) $ 14 $ — Amortization $ (17 ) $ 2 $ — Interest rate derivatives — — — Interest expense, net of amounts capitalized — (1 ) (1 ) Foreign currency derivatives 140 (58 ) — Interest expense, net of amounts capitalized (23 ) (13 ) — Other income (expense), net 159 (82 ) — Total $ 102 $ (44 ) $ — $ 119 $ (94 ) $ (1 ) There was no material ineffectiveness recorded in earnings for any period presented. The pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the Company's consolidated statements of income were not material for any year 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, 2017 , there was no collateral posted with the Company's derivative counterparties. At December 31, 2017 , the fair value of derivative liabilities with contingent features was $8 million . However, the fair value of derivative liabilities with contingent features, including 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 because of joint and several liability features underlying these derivatives, was $12 million at December 31, 2017 . 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 maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017 , cash collateral posted was immaterial. 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 Co GAS | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather 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. Wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For other businesses, the Company's policy is that derivatives are to be used primarily for hedging purposes. In both cases, the Company 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 net 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 natural gas price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, gas distribution operations has limited exposure to market volatility in prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the natural gas distribution utilities' respective state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. However, the Company retains exposure to price changes that can, in a volatile energy market, be extremely material and can adversely affect the Company. The Company also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income. Energy-related derivative contracts are accounted for under one of three methods: • Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through the respective 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) are initially deferred in other 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 in the period of change. 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 natural gas 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, 2017 , the net volume of energy-related derivative contracts for natural gas positions totaled 300 million mmBtu for the Company, together with the longest hedge date of 2020 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2026 for derivatives not designated as hedges. For cash flow hedges, the estimated pre-tax losses that will be reclassified from accumulated OCI to earnings for the 12-month period ending December 31, 2018 are $4 million . 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 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. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. In 2015, the Company executed $800 million in notional value of 10 -year and 30 -year fixed-rate forward-starting interest rate swaps to hedge potential interest rate volatility designated as cash flow hedges of issuances of long-term debt in the fourth quarter 2015 and during 2016. The Company settled $200 million of these interest rate swaps in 2015 for an immaterial loss, $400 million in May 2016 at a loss of $26 million , and the remaining $200 million in September 2016 at a loss of $35 million . Due to the application of acquisition accounting, only $5 million of the pre-tax loss incurred and deferred in the successor period is being amortized to interest expense through 2046. Derivative Financial Statement Presentation and Amounts The derivative contracts of the Company are subject to master netting arrangements or similar agreements and are reported net in the 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. At December 31, 2017 and 2016 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Assets from risk management activities/Liabilities from risk management activities-current $ 5 $ 8 $ 24 $ 3 Other deferred charges and assets/Other deferred credits and liabilities — — 1 — Total derivatives designated as hedging instruments for regulatory purposes $ 5 $ 8 $ 25 $ 3 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities/Liabilities from risk management activities-current $ — $ 3 $ 4 $ 3 Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities/Liabilities from risk management activities-current $ 379 $ 434 $ 486 $ 482 Other deferred charges and assets/Other deferred credits and liabilities 170 215 66 81 Total derivatives not designated as hedging instruments $ 549 $ 649 $ 552 $ 563 Gross amounts recognized $ 554 $ 660 $ 581 $ 569 Gross amounts offset (a) $ (390 ) $ (583 ) $ (435 ) $ (497 ) Net amounts recognized in the Balance Sheets (b) $ 164 $ 77 $ 146 $ 72 (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016 , respectively. (b) Net amount of derivative instruments outstanding excludes premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017 . At December 31, 2017 and 2016 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (4 ) $ (1 ) Other regulatory liabilities, current $ 7 $ 17 Other regulatory assets, deferred — — Other regulatory liabilities, deferred — 1 Total energy-related derivative gains (losses) (*) $ (4 ) $ (1 ) $ 7 $ 18 (*) Fair value gains and losses included in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million as of December 31, 2017 and $8 million as of December 31, 2016 . For all periods presented, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were as follows: Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Successor Successor Derivatives in Cash Flow Hedging Relationships 2017 Statements of Income Location 2017 (in millions) (in millions) Energy-related derivatives $ (9 ) Cost of natural gas $ (2 ) Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Successor Predecessor Successor Predecessor Derivatives in Cash Flow Hedging Relationships July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Statements of Income Location July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) (in millions) (in millions) Energy-related derivatives $ 2 $ — Cost of natural gas $ (1 ) $ (1 ) Interest rate derivatives (5 ) (64 ) Interest expense, net of amounts capitalized — — Total derivatives in cash flow hedging relationships $ (3 ) $ (64 ) $ (1 ) $ (1 ) Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Predecessor Predecessor Derivatives in Cash Flow Hedging Relationships 2015 Statements of Income Location 2015 (in millions) (in millions) Energy-related derivatives $ 3 Cost of natural gas $ (10 ) Other operations and maintenance (1 ) Interest rate derivatives — Interest expense, net of amounts capitalized 2 Total derivatives in cash flow hedging relationships $ 3 $ (9 ) There was no material ineffectiveness recorded in earnings for any period presented. For all periods presented, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Gain (Loss) Successor Predecessor Derivatives in Non-Designated Hedging Relationships Statements of Income Location Year Ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year Ended December 31, 2015 (in millions) (in millions) Energy-related derivatives Natural gas revenues (*) $ (80 ) $ 33 $ (1 ) $ 56 Cost of natural gas (2 ) 3 (62 ) (6 ) Total derivatives in non-designated hedging relationships $ (82 ) $ 36 $ (63 ) $ 50 (*) Excludes the impact of weather derivatives recorded in natural gas revenues of $23 million for the successor year ended December 31, 2017 , $6 million for the successor period of July 1, 2016 through December 31, 2016 , $3 million for the predecessor period of January 1, 2016 through June 30, 2016 , and $12 million for the predecessor year ended December 31, 2015 . 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 a credit rating change below BBB- and/or Baa3. At December 31, 2017 , the Company had no collateral posted with derivative counterparties to satisfy these arrangements. At December 31, 2017 , the fair value of derivative liabilities with contingent features was $3 million and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was $2 million . Generally, collateral may be provided by a 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 has 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. Prior to entering into a physical transaction, the Company assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. The Company may require counterparties to pledge additional collateral when deemed necessary. Credit evaluations are conducted and appropriate internal approvals are obtained for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, the Company requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings. The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the Company's credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Merger, Acquisitions, and Dispo
Merger, Acquisitions, and Dispositions | 12 Months Ended |
Dec. 31, 2017 | |
Business Acquisition [Line Items] | |
MERGER, ACQUISITION, AND DISPOSITIONS | ACQUISITIONS AND DISPOSITIONS Southern Company Merger with Southern Company Gas Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation: Southern Company Gas Purchase Price (in millions) Current assets $ 1,557 Property, plant, and equipment 10,108 Goodwill 5,967 Intangible assets 400 Regulatory assets 1,118 Other assets 229 Current liabilities (2,201 ) Other liabilities (4,742 ) Long-term debt (4,261 ) Noncontrolling interest (174 ) Total purchase price $ 8,001 The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes. The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years . The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3). The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $3.9 billion and $1.7 billion and net income of $243 million and $114 million for 2017 and 2016 , respectively. The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger. 2016 2015 Operating revenues (in millions) $ 21,791 $ 21,430 Net income attributable to Southern Company (in millions) $ 2,591 $ 2,665 Basic EPS $ 2.70 $ 2.85 Diluted EPS $ 2.68 $ 2.84 These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future. Acquisition of PowerSecure In May 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million . As a result, PowerSecure became a wholly-owned subsidiary of Southern Company. The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation: PowerSecure Purchase Price (in millions) Current assets $ 172 Property, plant, and equipment 46 Intangible assets 106 Goodwill 284 Other assets 4 Current liabilities (121 ) Long-term debt, including current portion (48 ) Deferred credits and other liabilities (14 ) Total purchase price $ 429 The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes. The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years . The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3). The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented. Southern Power During 2017 and 2016 , in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below. Also, in March 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, Southern Power and the class B member are now entitled to 66% and 34% , respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented. The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017 . Project Facility Resource Seller; Acquisition Date Approximate Nameplate Capacity (MW) Location Southern Power Percentage Ownership Actual/Expected COD PPA Contract Period Business Acquisitions During the Year Ended December 31, 2017 Bethel Wind Invenergy Wind Global LLC, January 6, 2017 276 Castro County, TX 100 % January 2017 12 years Cactus Flats (a) Wind RES America Developments, Inc. 148 Concho County, TX 100 % Third quarter 2018 12 years and 15 years Business Acquisitions Subsequent to December 31, 2017 Gaskell West 1 Solar Recurrent Energy Development Holdings, LLC, January 26, 2018 20 Kern County, CA 100% of Class B (b) March 20 years (a) On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. (b) Southern Power owns 100% of the class B membership interest under a tax equity partnership agreement. Business Acquisitions During the Year Ended December 31, 2017 Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million . The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows: 2017 (in millions) Restricted cash $ 16 CWIP 534 Other assets 5 Accounts payable (16 ) Total purchase price $ 539 In 2017, total revenues of $15 million and net income of $17 million , primarily as a result of PTCs, was recognized by Southern Power related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted. Construction Projects in Progress During the year ended December 31, 2017 , in accordance with its overall growth strategy, Southern Power continued construction on the 345 -MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million . At December 31, 2017, construction costs included in CWIP related to these projects totaled $188 million . The ultimate outcome of these matters cannot be determined at this time. Development Projects During 2017, as part of Southern Power's renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs. During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs. The ultimate outcome of these matters cannot be determined at this time. The following table presents Southern Power's acquisitions for the year ended December 31, 2016 . Project Facility Resource Seller, Acquisition Date Approximate MW ) Location Ownership Percentage Actual COD PPA Acquisitions for the Year Ended December 31, 2016 Boulder 1 Solar SunPower 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC 20 Imperial County, CA 100 % (b) February 2016 20 years East Pecos Solar First Solar, Inc. 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc. 102 Dawson County, TX 100 % April 2017 15 years Mankato (d) Natural Gas Calpine Corporation October 26, 2016 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC 74 Rutherford County, NC 100 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc. 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc. 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years (a) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) Southern Power originally purchased 90% , with a minority owner owning 10% . During 2017, Southern Power acquired the remaining 10% ownership interest. (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) Southern Power owns 90.1% , with the minority owner, Invenergy Wind Global LLC, owning 9.9% . Acquisitions During the Year Ended December 31, 2016 Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion . The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to Southern Power was approximately $2.6 billion for these acquisitions. In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: Southern Power (b) (c) $ 2,345 Noncontrolling interests (d) (e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 - and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. (b) At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. Southern Company Gas Investment in Southern Natural Gas In September 2016, Southern Company Gas completed its acquisition from Kinder Morgan, Inc. of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,000 -mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of the acquisition was approximately $1.4 billion . The investment in SNG is accounted for using the equity method. Acquisition of Remaining Interest in SouthStar SouthStar Energy Services, LLC (SouthStar) is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont Natural Gas Company, Inc.'s (Piedmont) owning the remaining 15% . In October 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million . Proposed Sale of Elizabethtown Gas and Elkton Gas On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion . The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time. |
SOUTHERN POWER CO | |
Business Acquisition [Line Items] | |
MERGER, ACQUISITION, AND DISPOSITIONS | ACQUISITIONS During 2017 and 2016 , in accordance with its overall growth strategy, the Company or one of its wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below. Also, in March 2016, the Company acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, the Company and the class B member are now entitled to 66% and 34% , respectively, of all cash distributions from Desert Stateline. In addition, the Company will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented. The following table presents the Company's acquisition activity for the year ended, and subsequent to, December 31, 2017. Project Facility Resource Seller, Acquisition Date Approximate Nameplate Capacity ( MW ) Location Ownership Percentage Actual / Expected COD PPA Contract Period Business Acquisitions During the Year Ended December 31, 2017 Bethel Wind Invenergy Wind Global LLC, 276 Castro County, TX 100 % January 2017 12 years Cactus Flats (a) Wind RES America Developments, Inc., 148 Concho County, TX 100 % Third quarter 2018 12 years and 15 years Asset Acquisitions Subsequent to December 31, 2017 Gaskell West 1 Solar Recurrent Energy Development Holdings, LLC, 20 Kern County, CA 100% of Class B (b) March 20 years (a) On July 31, 2017, the Company purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, the Company expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. (b) The Company owns 100% of the class B membership interest under a tax equity partnership agreement. Business Acquisitions During the Year Ended December 31, 2017 The Company's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million . The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows: 2017 (in millions) Restricted cash $ 16 CWIP 534 Other assets 5 Accounts payable (16 ) Total purchase price $ 539 In 2017, total revenues of $15 million and net income of $17 million , primarily as a result of PTCs, was recognized in the consolidated statements of income by the Company related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted. Construction Projects in Progress During the year ended December 31, 2017 , in accordance with its overall growth strategy, the Company continued construction on the 345 -MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million . At December 31, 2017 , construction costs included in CWIP related to these projects totaled $188 million . The ultimate outcome of these matters cannot be determined at this time. Development Projects During 2017, as part of the Company's renewable development strategy, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs. During 2016, the Company entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs. The ultimate outcome of these matters cannot be determined at this time. The following table presents the Company's acquisitions for the year ended December 31, 2016 . Project Facility Resource Seller, Acquisition Date Approximate MW ) Location Ownership Percentage Actual COD PPA Acquisitions for the Year Ended December 31, 2016 Boulder 1 Solar SunPower Corporation, 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC, 20 Imperial County, CA 100 % (b) February 2016 20 years East Pecos Solar First Solar, Inc., 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC, 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC, 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower Corporation, 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc., 102 Dawson County, TX 100 % April 2017 15 years Mankato (d) Natural Gas Calpine Corporation, 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC, 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC, 74 Rutherford County, NC 100 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc., 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc., 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy Wind Global LLC, 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years (a) The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) The Company originally purchased 90% , with a minority owner owning 10% . During 2017, the Company acquired the remaining 10% ownership interest. See Note 10 for additional information. (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) The Company owns 90.1% , with the minority owner, Invenergy Wind Global LLC, owning 9.9% . Acquisitions During the Year Ended December 31, 2016 The Company's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion . The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to the Company was approximately $2.6 billion for these acquisitions. In connection with the Company's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: The Company (b) (c) $ 2,345 Noncontrolling interests (d) (e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 - and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. (b) At December 31, 2016, $461 million is included in acquisitions payable on the consolidated balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. |
SOUTHERN Co GAS | |
Business Acquisition [Line Items] | |
MERGER, ACQUISITION, AND DISPOSITIONS | MERGER, ACQUISITION, AND DISPOSITIONS Merger with Southern Company On July 1, 2016, the Company completed the Merger with Southern Company. A wholly-owned, direct subsidiary of Southern Company merged with and into Southern Company Gas, with the Company surviving as a wholly-owned, direct subsidiary of Southern Company. At the effective time of the Merger, each share of Southern Company Gas common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the Merger, all of the outstanding restricted stock units, restricted stock awards, non-employee director stock awards, stock options, and performance share units were either redeemed or converted into Southern Company's restricted stock units. See Note 8 for additional information. The application of the acquisition method of accounting was pushed down to the Company. The excess of the purchase price over the fair values of the Company's assets and liabilities was recorded as goodwill, which represents a different basis of accounting from the historical basis prior to the Merger. The following table presents the final purchase price allocation: Successor Predecessor New Basis Old Basis Change in Basis (in millions) (in millions) Current assets $ 1,557 $ 1,474 $ 83 Property, plant, and equipment 10,108 10,148 (40 ) Goodwill 5,967 1,813 4,154 Other intangible assets 400 101 299 Regulatory assets 1,118 679 439 Other assets 229 273 (44 ) Current liabilities (2,201 ) (2,205 ) 4 Other liabilities (4,742 ) (4,600 ) (142 ) Long-term debt (4,261 ) (3,709 ) (552 ) Contingently redeemable noncontrolling interest (174 ) (41 ) (133 ) Total purchase price/equity $ 8,001 $ 3,933 $ 4,068 Measurement period adjustments were recorded to the purchase price allocation during the fourth quarter 2016, which resulted in a net $30 million increase in goodwill to establish intangible liabilities for transportation contracts at wholesale services, partially offset by adjustments to deferred tax balances. In determining the fair value of assets and liabilities subject to rate regulation that allows recovery of costs and/or a fair return on investments, historical cost was deemed to be a reasonable proxy for fair value, as it is included in rate base or otherwise specified in regulatory recovery mechanisms. Property, plant, and equipment subject to rate regulation was reflected based on the historical gross amount of assets in service and accumulated depreciation, as they are included in rate base. For certain assets and liabilities subject to rate regulation (such as debt instruments and employee benefit obligations), the fair value adjustment was applied to historical cost with a corresponding offset to regulatory asset or liability based on the assessment of probable future recovery in rates. For unregulated assets and liabilities, fair value adjustments were applied to historical cost of natural gas for sale, property, plant, and equipment, debt instruments, and noncontrolling interest. The valuation of other intangible assets included customer relationships, trade names, and favorable/unfavorable contracts. The valuation of these assets and liabilities applied either the market approach or income approach. The market approach was utilized when prices and other relevant market information were available. The income approach, which is based on discounted cash flows, was primarily based on significant unobservable inputs (Level 3). Key estimates and inputs included forecasted profitability and cash flows, customer retention rates, royalty rates, and discount rates. The estimated fair value of deferred income taxes was determined by applying the appropriate enacted statutory tax rate to the temporary differences that arose on the differences between the financial reporting value and tax basis of the assets acquired and liabilities assumed. The excess of the purchase price over the estimated fair value of assets and liabilities of $6 billion was recognized as goodwill, which is primarily attributable to positioning Southern Company to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. The Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes. The receipt of required regulatory approvals was conditioned upon certain terms and commitments. In connection with these regulatory approvals, certain regulatory agencies prohibited the Company from recovering goodwill and Merger-related expenses, required the Company to maintain a minimum number of employees for a set period of time to ensure that certain pipeline safety standards and the competence level of the employee workforce is not degraded, and/or required the Company to maintain its pre-Merger level of support for various social and charitable programs. The most notable terms and commitments with potential financial impacts included: • rate credits of $18 million to be paid to customers in New Jersey and Maryland; • sharing of Merger savings with customers in Georgia starting in 2020; • phasing-out the use of the Nicor name or logo by certain of the Company's gas marketing services subsidiaries in conducting non-utility business in Illinois; • reaffirming that Elizabethtown Gas would file a base rate case no later than September 1, 2016, with another base rate case no later than three years after the 2016 rate case; and • requiring Elkton Gas to file a base rate case within two years of closing the Merger. There is no restriction on the Company's other utilities' ability to file future rate cases. The rate credits to customers in New Jersey and Maryland were paid during the third and fourth quarters of 2016, respectively. The use of the Nicor name and logo was phased out, effective November 1, 2017, by certain of the Company's gas marketing services subsidiaries in conducting non-utility business in Illinois. Elizabethtown Gas filed a base rate case with the New Jersey BPU on September 1, 2016. See Note 3 under "Base Rate Cases" for additional information. Upon completion of the Merger, the Company amended and restated its Bylaws and Articles of Incorporation, under which it now has the authority to issue no more than 110 million shares of stock consisting of (i) 100 million shares of common stock and (ii) 10 million shares of preferred stock, both categories of which have a par value of $0.01 per share. The amended and restated Articles of Incorporation do not allow any treasury shares to be held. Investment in SNG In September 2016, the Company, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG pursuant to a definitive agreement between Southern Company and Kinder Morgan, Inc. in July 2016, to which Southern Company assigned all rights and obligations to the Company in August 2016. SNG owns a 7,000 -mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of $1.4 billion was financed by a $1.05 billion equity contribution from Southern Company and $360 million of cash paid by the Company, which was financed by a promissory note from Southern Company repaid with a portion of the proceeds from senior notes issued in September 2016. The purchase price of the 50% equity interest exceeded the underlying ownership interest in the net assets of SNG by approximately $700 million . This basis difference is attributable to goodwill and deferred tax assets. While the deferred tax assets will be amortized through deferred tax expense, the goodwill will not be amortized and is not required to be tested for impairment on an annual basis. The Company's investment in SNG decreased by $104 million related to the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. On March 31, 2017, the Company made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 4 under "Equity Method Investments" for additional information on this investment. Proposed Sale of Elizabethtown Gas and Elkton Gas On October 15, 2017, the Company's subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion . The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. The Company and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time. |
Segment and Related Information
Segment and Related Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | |
SEGMENT AND RELATED INFORMATION | SEGMENT AND RELATED INFORMATION The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $392 million , $419 million , and $417 million in 2017 , 2016 , and 2015 , respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were $23 million and $119 million , respectively, in 2017 and $11 million and $17 million , respectively, in 2016 . The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as 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, 2017 , 2016 , and 2015 was as follows: Electric Utilities Traditional Electric Operating Companies Southern Power Eliminations Total Southern Company Gas All Other Eliminations Consolidated (in millions) 2017 Operating revenues $ 16,884 $ 2,075 $ (419 ) $ 18,540 $ 3,920 $ 741 $ (170 ) $ 23,031 Depreciation and amortization 1,954 503 — 2,457 501 52 — 3,010 Interest income 14 7 — 21 3 11 (9 ) 26 Earnings from equity method investments 1 — — 1 106 (1 ) — 106 Interest expense 820 191 — 1,011 200 490 (7 ) 1,694 Income taxes 1,021 (939 ) — 82 367 (307 ) — 142 Segment net income (loss) (a)(b)(c) (193 ) 1,071 — 878 243 (279 ) — 842 Total assets 72,204 15,206 (325 ) 87,085 22,987 2,552 (1,619 ) 111,005 Gross property additions 3,836 268 — 4,104 1,525 355 — 5,984 2016 Operating revenues $ 16,803 $ 1,577 $ (439 ) $ 17,941 $ 1,652 $ 463 $ (160 ) $ 19,896 Depreciation and amortization 1,881 352 — 2,233 238 31 — 2,502 Interest income 6 7 — 13 2 20 (15 ) 20 Earnings from equity method investments 2 — — 2 60 (3 ) — 59 Interest expense 814 117 — 931 81 317 (12 ) 1,317 Income taxes 1,286 (195 ) — 1,091 76 (216 ) — 951 Segment net income (loss) (a) (b) 2,233 338 — 2,571 114 (230 ) (7 ) 2,448 Total assets 72,141 15,169 (316 ) 86,994 21,853 2,474 (1,624 ) 109,697 Gross property additions 4,852 2,114 — 6,966 618 41 (1 ) 7,624 2015 Operating revenues $ 16,491 $ 1,390 $ (439 ) $ 17,442 $ — $ 152 $ (105 ) $ 17,489 Depreciation and amortization 1,772 248 — 2,020 — 14 — 2,034 Interest income 19 2 1 22 — 6 (5 ) 23 Earnings from equity method investments 1 — — 1 — (1 ) — — Interest expense 697 77 — 774 — 69 (3 ) 840 Income taxes 1,305 21 — 1,326 — (132 ) — 1,194 Segment net income (loss) (a) (b) 2,186 215 — 2,401 — (32 ) (2 ) 2,367 Total assets 69,052 8,905 (397 ) 77,560 — 1,819 (1,061 ) 78,318 Gross property additions 5,124 1,005 — 6,129 — 40 — 6,169 (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.4 billion ( $2.4 billion after tax) in 2017, $428 million ( $264 million after tax) in 2016, and $365 million ( $226 million after tax) in 2015. See Note 3 under " Kemper County Energy Facility – Schedule and Cost Estimate " for additional information. (c) Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ( $20 million after tax) in 2017. See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. Products and Services Electric Utilities' Revenues Year Retail Wholesale Other Total (in millions) 2017 $ 15,330 $ 2,426 $ 784 $ 18,540 2016 15,234 1,926 781 17,941 2015 14,987 1,798 657 17,442 Southern Company Gas' Revenues Year Gas Gas All Other Total (in millions) 2017 $ 3,024 $ 860 $ 36 $ 3,920 2016 1,266 354 32 1,652 |
SOUTHERN Co GAS | |
Segment Reporting Information [Line Items] | |
SEGMENT AND RELATED INFORMATION | SEGMENT AND RELATED INFORMATION The Company manages its business through four reportable segments - gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. The non-reportable segments are combined and presented as all other. In conjunction with the Merger, the Company changed the names of certain reportable segments to better align with its new parent company. Gas distribution operations is the largest component of the Company's business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. Wholesale gas services provides natural gas asset management and/or related logistics services for each of the Company's utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Since the acquisition of the Company's 50% interest in SNG, gas midstream operations primarily consists of the Company's gas pipeline investments, with storage and fuel operations also aggregated into this segment. The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure. After the Merger, the Company changed the segment performance measure to net income, which is utilized by its parent company. In order to properly assess net income by segment, the Company executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor periods, the Company is unable to provide the comparable net income for those periods. Financial data for business segments for the successor year ended December 31, 2017 , the successor period of July 1, 2016 through December 31, 2016 , and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were as follows: Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (a) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Successor – Year ended December 31, 2017 Operating revenues $ 3,207 $ 860 $ 6 $ 71 $ 4,144 $ 10 $ (234 ) $ 3,920 Depreciation and 391 62 2 18 473 28 — 501 Operating income (loss) 650 113 (51 ) (10 ) 702 (37 ) — 665 Earnings from equity method investments — — — 103 103 3 — 106 Interest expense (153 ) (5 ) (7 ) (33 ) (198 ) (2 ) — (200 ) Income taxes (b) 178 24 — 61 263 104 — 367 Segment net income (loss) (b) 353 84 (57 ) 3 383 (140 ) — 243 Gross property 1,330 9 1 134 1,474 34 — 1,508 Successor – Total assets 19,358 2,147 1,096 2,241 24,842 12,184 (14,039 ) 22,987 Successor – July 1, 2016 through December 31, 2016 Operating revenues $ 1,342 $ 354 $ 24 $ 31 $ 1,751 $ 3 $ (102 ) $ 1,652 Depreciation and 185 35 1 9 230 8 — 238 Operating income (loss) 222 27 (2 ) (7 ) 240 (43 ) — 197 Earnings from equity — — — 58 58 2 — 60 Interest expense (105 ) (1 ) (3 ) (16 ) (125 ) 44 — (81 ) Income taxes 51 7 (3 ) 16 71 5 — 76 Segment net income (loss) 77 19 — 20 116 (2 ) — 114 Gross property 561 5 1 54 621 11 — 632 Successor – Total assets 19,453 2,084 1,127 2,211 24,875 11,145 (14,167 ) 21,853 Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (a) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Predecessor – January 1, 2016 through June 30, 2016 Operating revenues $ 1,575 $ 435 $ (32 ) $ 25 $ 2,003 $ 4 $ (102 ) $ 1,905 Depreciation and 178 11 1 9 199 7 — 206 Operating income (loss) 351 109 (69 ) (9 ) 382 (61 ) — 321 EBIT 353 109 (68 ) (6 ) 388 (60 ) — 328 Gross property additions 484 4 1 43 532 16 — 548 Predecessor – Year Ended December 31, 2015 Operating revenues $ 3,049 $ 835 $ 202 $ 55 $ 4,141 $ 11 $ (211 ) $ 3,941 Depreciation and 336 25 1 18 380 17 — 397 Operating income (loss) 571 152 112 (26 ) 809 (63 ) — 746 EBIT 581 152 110 (23 ) 820 (59 ) — 761 Gross property additions 957 7 2 27 993 34 — 1,027 Predecessor – Total 12,519 686 935 692 14,832 9,662 (9,740 ) 14,754 (a) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. Third Party Gross Revenues Intercompany Revenues Total Gross Revenues Less Gross Gas Costs Operating Revenues (in millions) Successor – Year Ended $ 6,152 $ 481 $ 6,633 $ 6,627 $ 6 Su ccessor – July 1, 2016 through 5,807 333 6,140 6,116 24 (in millions) Predecessor – January 1, 2016 through $ 2,500 $ 143 $ 2,643 $ 2,675 $ (32 ) Predecessor – Year Ended December 31, 2015 6,286 408 6,694 6,492 202 (b) Includes the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. |
Noncontrolling Interest
Noncontrolling Interest | 12 Months Ended |
Dec. 31, 2017 | |
SOUTHERN POWER CO | |
Noncontrolling Interest [Line Items] | |
NONCONTROLLING INTEREST | NONCONTROLLING INTERESTS In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to non-redeemable noncontrolling interests due to the expiration of an option allowing SunPower Corporation to require the Company to purchase its redeemable noncontrolling interest at fair market value. In addition, Turner Renewable Energy, LLC owned a 10% redeemable noncontrolling interest in certain of the Company's solar facilities. These noncontrolling interests were redeemed in October 2017 at fair market value pursuant to the partnership agreement. As of December 31, 2017 , there were no outstanding redeemable noncontrolling interests. The following table presents the changes in redeemable noncontrolling interests for the years ended December 31: 2017 2016 2015 (in millions) Beginning balance $ 164 $ 43 $ 39 Net income attributable to redeemable noncontrolling interests 2 4 2 Distributions to redeemable noncontrolling interests (2 ) (1 ) — Capital contributions from redeemable noncontrolling interests 2 118 2 Redemption of redeemable noncontrolling interests (59 ) — — Reclassification to non-redeemable noncontrolling interests (114 ) — — Change in fair value of redeemable noncontrolling interests 7 — — Ending balance $ — $ 164 $ 43 The following table presents the attribution of net income to the Company and the noncontrolling interests for the years ended December 31: 2017 2016 2015 (in millions) Net income $ 1,117 $ 374 $ 229 Less: Net income attributable to noncontrolling interests 44 32 12 Less: Net income attributable to redeemable noncontrolling interests 2 4 2 Net income attributable to the Company $ 1,071 $ 338 $ 215 |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2017 and 2016 is as follows: Consolidated Net Income Attributable to Southern Company Per Common Share Operating Revenues Operating Income Basic Earnings Diluted Earnings Trading Price Range Quarter Ended Dividends High Low (in millions) March 2017 $ 5,771 $ 1,306 $ 658 $ 0.66 $ 0.66 $ 0.5600 $ 51.47 $ 47.57 June 2017 5,430 (1,594 ) (1,381 ) (1.38 ) (1.37 ) 0.5800 51.97 47.87 September 2017 6,201 2,045 1,069 1.07 1.06 0.5800 50.80 46.71 December 2017 5,629 794 496 0.49 0.49 0.5800 53.51 47.92 March 2016 $ 3,992 $ 940 $ 489 $ 0.53 $ 0.53 $ 0.5425 $ 51.73 $ 46.00 June 2016 4,459 1,185 623 0.67 0.66 0.5600 53.64 47.62 September 2016 6,264 1,917 1,139 1.18 1.17 0.5600 54.64 50.00 December 2016 5,181 587 197 0.20 0.20 0.5600 52.23 46.20 As a result of the revisions to the cost estimate for the Kemper IGCC and its June 2017 suspension, Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $208 million ( $185 million after tax) in the fourth quarter 2017, $34 million ( $21 million after tax) in the third quarter 2017, $3.0 billion ( $2.1 billion after tax) in the second quarter 2017, $108 million ( $67 million after tax) in the first quarter 2017, $206 million ( $127 million after tax) in the fourth quarter 2016, $88 million ( $54 million after tax) in the third quarter 2016, $81 million ( $50 million after tax) in the second quarter 2016, and $53 million ( $33 million after tax) in the first quarter 2016. See Note 3 under " Kemper County Energy Facility " for additional information. As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million in the fourth quarter 2017. See Note 5 for additional information. The Southern Company system's business is influenced by seasonal weather conditions. |
ALABAMA POWER CO | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2017 $ 1,382 $ 376 $ 174 June 2017 1,484 454 230 September 2017 1,740 616 325 December 2017 1,433 268 119 March 2016 $ 1,331 $ 333 $ 156 June 2016 1,444 430 213 September 2016 1,785 650 351 December 2016 1,329 252 102 The Company's business is influenced by seasonal weather conditions. |
GEORGIA POWER CO | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2017 $ 1,832 $ 501 $ 260 June 2017 2,048 639 347 September 2017 2,546 1,034 580 December 2017 1,884 470 227 March 2016 $ 1,872 $ 509 $ 269 June 2016 2,051 656 349 September 2016 2,698 1,054 599 December 2016 1,762 258 113 The Company's business is influenced by seasonal weather conditions. |
GULF POWER CO | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in millions) March 2017 $ 350 $ 46 $ 18 June 2017 357 75 35 September 2017 437 115 63 December 2017 372 53 19 March 2016 $ 335 $ 65 $ 29 June 2016 365 74 34 September 2016 436 90 45 December 2016 349 54 23 The Company's business is influenced by seasonal weather conditions. |
MISSISSIPPI POWER CO | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) After Dividends on Preferred Stock (in millions) March 2017 $ 272 $ (62 ) $ (20 ) June 2017 303 (2,954 ) (2,054 ) September 2017 341 51 40 December 2017 271 (177 ) (556 ) March 2016 $ 257 $ (10 ) $ 11 June 2016 277 (28 ) 2 September 2016 352 9 26 December 2016 277 (166 ) (89 ) As a result of the revisions to the cost estimate for the Kemper IGCC and its June 2017 suspension, the Company recorded total pre-tax charges to income related to the Kemper IGCC of $208 million ( $185 million after tax) in the fourth quarter 2017, $34 million ( $21 million after tax) in the third quarter 2017, $3.0 billion ( $2.1 billion after tax) in the second quarter 2017, $108 million ( $67 million after tax) in the first quarter 2017, $206 million ( $127 million after tax) in the fourth quarter 2016, $88 million ( $54 million after tax) in the third quarter 2016, $81 million ( $50 million after tax) in the second quarter 2016, and $53 million ( $33 million after tax) in the first quarter 2016. See Note 3 under "Kemper County Energy Facility" for additional information. As a result of Tax Reform Legislation, the Company recorded total income tax expense of $372 million in the fourth quarter 2017. See Note 5 for additional information. The Company's business is influenced by seasonal weather conditions. |
SOUTHERN POWER CO | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Income Tax (Benefit) Net Income Attributable to the Company (in millions) March 2017 $ 450 $ 65 $ (52 ) $ 70 June 2017 529 112 (38 ) 82 September 2017 618 159 (39 ) 124 December 2017 (*) 478 32 (810 ) 795 March 2016 $ 315 $ 47 $ (23 ) $ 50 June 2016 373 81 (41 ) 89 September 2016 500 134 (102 ) 176 December 2016 389 28 (29 ) 23 (*) As a result of the Tax Reform Legislation, the Company recorded an income tax benefit of $ 743 million in the fourth quarter 2017. See Note 5 for additional information. The Company's business is influenced by seasonal weather conditions. |
SOUTHERN Co GAS | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 and for the predecessor period of January 1, 2016 through June 30, 2016 are as follows: Quarter Ended Operating Operating EBIT Net Income (Loss) Attributable to Southern Company Gas (in millions) Successor - 2017 March 2017 $ 1,560 $ 391 $ 435 $ 239 June 2017 716 96 128 49 September 2017 (a) 565 68 118 15 December 2017 (a)(b) 1,079 110 129 (60 ) Predecessor - January 1, 2016 through June 30, 2016 (in millions) March 2016 $ 1,334 $ 348 $ 351 $ 182 June 2016 571 (27 ) (23 ) (51 ) Successor - July 1, 2016 through December 31, 2016 (in millions) September 2016 $ 543 $ 12 $ 50 $ 4 December 2016 1,109 185 221 110 (a) Net income (loss) attributable to Southern Company Gas includes the impact of new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. (b) Net loss attributable to Southern Company Gas includes the impact of the Tax Reform Legislation. The Company's business is influenced by seasonal weather conditions. See Note 11 under "Merger with Southern Company" for information on the Merger. |
Valuation and Qualifying Accoun
Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 , 2016 , AND 2015 (Stated in Thousands of Dollars) Additions Description Balance at Beginning of Period Charged to Income Charged to Other Accounts Acquisitions Deductions (Note) Balance at End of Period Provision for uncollectible accounts 2017 $ 43,429 $ 55,770 $ (248 ) $ 30 $ 54,605 $ 44,376 2016 13,341 39,959 (1,257 ) 40,629 49,243 43,429 2015 18,253 31,074 — — 35,986 13,341 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
ALABAMA POWER CO | |
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, 2017 , 2016 , AND 2015 (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 2017 $ 10,487 $ 9,367 $ — $ 11,075 $ 8,779 2016 9,597 11,310 — 10,420 10,487 2015 9,143 13,500 — 13,046 9,597 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
GEORGIA POWER CO | |
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, 2017 , 2016 , AND 2015 (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 2017 $ 2,836 $ 11,250 $ — $ 11,474 $ 2,612 2016 2,147 14,476 — 13,787 2,836 2015 6,076 16,862 — 20,791 2,147 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
GULF POWER CO | |
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, 2017 , 2016 , AND 2015 (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 2017 $ 732 $ 2,859 $ — $ 2,846 $ 745 2016 775 2,946 — 2,989 732 2015 2,087 2,041 — 3,353 775 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
MISSISSIPPI POWER CO | |
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, 2017 , 2016 , AND 2015 (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 2017 $ 494 $ 1,377 $ — $ 1,279 $ 592 2016 287 1,295 — 1,088 494 2015(*) 825 (1,994 ) — (1,456 ) 287 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. (*) The refund ordered by the Mississippi PSC pursuant to the 2015 Mississippi Supreme Court decision relative to a regulatory liability used by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility involved refunding all billed amounts to all historical customers and included an interest component. The refund of approximately $371 million in 2015 was of sufficient magnitude to resolve most past due amounts beyond 30 days aged receivables, accounting for the negative provision of $(2.0) million where risk of collectibility was offset by applying the refund to past due amounts. It was also of sufficient size to offset amounts previously written off in the 2012-2015 time frame, accounting for the net recoveries of $1.5 million . |
SOUTHERN Co GAS | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
VALUATION AND QUALIFYING ACCOUNTS | SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS FOR THE SUCCESSOR PERIODS OF JULY 1, 2016 THROUGH DECEMBER 31, 2016 AND THE YEAR ENDED DECEMBER 31, 2017 AND THE PREDECESSOR PERIODS OF JANUARY 1, 2016 THROUGH JUNE 30, 2016 AND THE YEAR ENDED DECEMBER 31, 2015 (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 Successor – December 31, 2017 Provision for uncollectible accounts $ 27,316 $ 28,022 $ (248 ) $ 27,286 $ 27,804 Income tax valuation 19,182 — — 7,910 11,272 Successor – December 31, 2016 Provision for uncollectible accounts $ 37,663 $ 9,500 $ (1,257 ) $ 18,590 $ 27,316 Income tax valuation 19,182 — — — 19,182 Predecessor – June 30, 2016 Provision for uncollectible accounts $ 29,142 $ 15,976 $ 1,608 $ 9,063 $ 37,663 Income tax valuation 19,182 — — — 19,182 Predecessor – 2015 Provision for uncollectible accounts $ 35,069 $ 27,050 $ 3,017 $ 35,994 $ 29,142 Income tax valuation 19,637 — — 455 19,182 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
Summary of Significant Accoun30
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Line Items] | |
General | General The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities. 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. Intercompany transactions have been eliminated in consolidation. The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. 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. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term , as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs , energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019. Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans $ 3,931 $ 3,959 (a,n) Asset retirement obligations-asset 1,133 1,080 (b,n) Deferred income tax charges 814 1,590 (b,p) Environmental remediation-asset 511 491 (j,n) Property damage reserves-asset 333 206 (i) Under recovered regulatory clause revenues 317 273 (g) Remaining net book value of retired assets 306 351 (o) Loss on reacquired debt 223 243 (c) Vacation pay 183 182 (f,n) Long-term debt fair value adjustment 138 155 (d) Deferred PPA charges 119 141 (e,n) Kemper County energy facility 88 201 (h) Other regulatory assets 511 487 (k) Deferred income tax credits (7,261 ) (219 ) (b,p) Other cost of removal obligations (2,684 ) (2,774 ) (b) Over recovered regulatory clause revenues (155 ) (203 ) (g) Property damage reserves-liability (135 ) (177 ) (l) Other regulatory liabilities (266 ) (120 ) (m) Total regulatory assets (liabilities), net $ (1,894 ) $ 5,866 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 other cost of removal obligations 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 80 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (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) Recovered over the remaining life of the original debt issuances, which range up to 21 years . For additional information see Note 12 under " Southern Company – Merger with Southern Company Gas ." (e) Recovered over the life of the PPA for periods up to six 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 or other applicable regulatory agencies over periods generally not exceeding 10 years . (h) Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years , respectively. For additional information, see Note 3 under " Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement ." (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under " Regulatory Matters – Georgia Power – Storm Damage Recovery " for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years . (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years . (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 48 years . (p) As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under " Regulatory Matters " and Note 5 for additional information. In the event that a portion of a traditional electric operating company's or a natural gas distribution utility'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 electric operating company or natural gas distribution utility 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 " Regulatory Matters – Alabama Power ," " – Georgia Power ," " – Gulf Power ," and " – Southern Company Gas " and " Kemper County Energy Facility " 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. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. For the traditional electric operating companies, 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 tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months . Programs of this type include weather normalization adjustments, revenue normalization mechanisms, and revenue true-up adjustments and are referred to as alternative revenue programs. Southern Company's electric utility subsidiaries and Southern Company Gas 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. |
Cost Of Natural Gas | Cost of Natural Gas Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively. |
Development Costs | Development Costs The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income. |
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 electric operating companies and Southern Company Gas 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. Under current tax law, 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. 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. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2017 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which would result in income tax benefits in the future, if utilized. See Note 5 under " Current and Deferred Income Taxes – Tax Credit Carryforwards " and " – Net Operating Loss " for additional information. Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. |
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: 2017 2016 (in millions) Electric utilities: Generation $ 51,279 $ 48,836 Transmission 11,562 11,156 Distribution 19,239 18,418 General 4,276 4,629 Plant acquisition adjustment 126 126 Electric utility plant in service 86,482 83,165 Natural gas distribution utilities: Transportation and distribution 13,078 11,996 Utility plant in service 99,560 95,161 Information technology equipment and software 752 544 Communications equipment 456 424 Storage facilities 1,598 1,463 Other 1,176 824 Total other plant in service 3,982 3,255 Total plant in service $ 103,542 $ 98,416 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. In accordance with their respective state PSC orders, Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle, which ranges from 18 to 24 months . 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, 2017 2016 (in millions) Office buildings $ 216 $ 61 Nitrogen plant (*) — 83 Computer-related equipment 51 63 Gas pipeline 6 6 Less: Accumulated amortization (72 ) (69 ) Balance, net of amortization $ 201 $ 144 (*) Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information. The amount of non-cash property additions recognized for the years ended December 31, 2017 , 2016 , and 2015 was $985 million , $1.3 billion , and $844 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, 2017 , 2016 , and 2015 was $162 million , $18 million , and $13 million , respectively. |
Depreciation 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 2.9% in 2017 and 3.0% in each of 2016 and 2015 . Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $30.8 billion and $29.3 billion at December 31, 2017 and 2016 , 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 related to natural gas-fired facilities are 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. Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under " Regulatory Matters – Gulf Power – Retail Base Rate Cases " for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from two to 65 years . Accumulated depreciation for other plant in service totaled $673 million and $550 million at December 31, 2017 and 2016 , respectively. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other 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 and amounts to be recovered are reflected in the balance sheet as a regulatory asset. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric 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 as 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: 2017 2016 (in millions) Balance at beginning of year $ 4,514 $ 3,759 Liabilities incurred 16 66 Liabilities settled (177 ) (171 ) Accretion 179 162 Cash flow revisions 292 698 Balance at end of year $ 4,824 $ 4,514 In 2017 and 2016 , the increases in cash flow revisions are primarily related to changes in closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities settled are primarily related to ash pond closure activity. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary. |
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, 2017 and 2016 , approximately $76 million and $56 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 $77 million and $58 million at December 31, 2017 and 2016 , 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, 2017 , investment securities in the Funds totaled $1.8 billion , consisting of equity securities of $1.1 billion , debt securities of $725 million , and $47 million of other securities. At December 31, 2016 , investment securities in the Funds totaled $1.6 billion , consisting of equity securities of $878 million , debt securities of $685 million , and $41 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 securities lending program. Sales of the securities held in the Funds resulted in cash proceeds of $0.8 billion , $1.2 billion , and $1.4 billion in 2017 , 2016 , and 2015 , respectively, all of which were reinvested. For 2017 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $233 million , which included $181 million related to unrealized gains on securities held in the Funds at December 31, 2017 . For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $114 million , which included $48 million related to unrealized losses on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $11 million , which included $83 million related to unrealized gains and losses on securities held in the Funds at December 31, 2015 . 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, approximately $18 million and $19 million at December 31, 2017 and 2016 , respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as 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, 2017 and 2016 , the accumulated provisions for the external decommissioning trust funds were as follows: External Trust Funds 2017 2016 (in millions) Plant Farley $ 902 $ 790 Plant Hatch 583 511 Plant Vogtle Units 1 and 2 346 303 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, 2017 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 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 2075 2079 (in millions) Site study costs: Radiated structures $ 1,362 $ 678 $ 568 Spent fuel management — 160 147 Non-radiated structures 80 64 89 Total site study costs $ 1,442 $ 902 $ 804 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 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 review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in Georgia Power's 2019 base rate case. 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 The traditional electric operating companies and certain of the natural gas distribution utilities 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, 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 electric operating companies' and natural gas distribution utilities' regulated rates is capitalized in accordance with standard interest capitalization requirements. |
Goodwill and Other Intangible Assets and Liabilities | Goodwill and Other Intangible Assets and Liabilities Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any. For the 2017 annual impairment test, the Company performed Step 1 of the two-step impairment test, which resulted in the fair value of all its reporting units that have goodwill exceeding their carrying value. For the 2016 and 2015 annual impairment tests, the Company performed the qualitative Step 0 assessment and determined that it was more likely than not that the fair value of all its reporting units with goodwill exceeded their carrying values, and therefore no quantitative assessment was required. In the third quarter 2015, the Company identified potential impairment indicators and performed an interim impairment test for its storage and fuels reporting unit, which resulted in impairment of the full $14 million goodwill balance for that reporting unit. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets 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 and Environmental Remediation Recovery | Storm Damage Reserves Each traditional electric 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 electric operating companies accrued $41 million in 2017 and $40 million in each of 2016 and 2015 . 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 2017 , 2016 , and 2015 , there were no such additional accruals. |
Leveraged Leases | Leveraged Leases A subsidiary of Southern Holdings 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. Southern 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. |
Restricted Cash, 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 of the electric utilities. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric 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. |
Natural Gas for Sale | Natural Gas for Sale The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income. Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. |
Financial Instruments and Derivatives | 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 on the balance sheets (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 electric operating companies' and the natural gas distribution utilities' 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. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2017 , 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 potential 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. |
Fair Value Measurement | 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. Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded and 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. 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' judgments, are also obtained when available. See Note 1 under " Nuclear Decommissioning " for additional information. Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial. "Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions. |
ALABAMA POWER CO | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Alabama Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service 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 develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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 Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. |
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 $479 million , $460 million , and $438 million during 2017 , 2016 , and 2015 , 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. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment. 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 $248 million , $249 million , and $243 million during 2017 , 2016 , and 2015 , 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 totaled $9 million in 2017 , $13 million in 2016 , and $11 million in 2015 . Mississippi Power also reimbursed the Company for any direct fuel purchases delivered from one of the Company's transfer facilities. There were no such fuel purchases in 2017 and 2016 and $8 million in 2015 . See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. Under a related tariff, the Company received $11 million in 2017, $12 million in 2016, and $14 million in 2015 and expects to recover a total of approximately $61 million from 2018 through 2023 from Gulf Power. In September 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were approximately $9 million in 2017 and $2 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016 . The Company has agreements with PowerSecure for services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs for these services amounted to approximately $11 million for 2017 and were immaterial for 2016. 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 2017 , 2016 , or 2015 . Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional electric 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans $ 946 $ 947 (i,j) Deferred income tax charges 240 526 (a,k,n) Regulatory clauses 142 — (m) Vacation pay 70 69 (c,j) Loss on reacquired debt 62 68 (b) Nuclear outage 56 70 (d) Remaining net book value of retired assets 54 69 (l) Under/(over) recovered regulatory clause revenues 53 76 (d) Other regulatory assets 51 50 (f) Fuel-hedging losses 7 1 (e,j) Deferred income tax credits (2,082 ) (65 ) (a,n) Other cost of removal obligations (609 ) (684 ) (a) Natural disaster reserve (38 ) (69 ) (h) Asset retirement obligations (33 ) 12 (a) Other regulatory liabilities (7 ) (23 ) (e,g) Total regulatory assets (liabilities), net $ (1,088 ) $ 1,047 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 credits are amortized over the related property lives, which may range up to 50 years . Asset retirement and other cost of 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 . See Note 3 under "Retail Regulatory Matters" for additional information. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half 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 (to be recovered over the next 12 months ), 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 fuel-hedging gains. 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 $13 million for 2017 and $16 million for 2016 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 up to 11 years . (m) Established per an order from the Alabama PSC issued on February 17, 2017 and will be amortized concurrently with the effective date of the Company's next depreciation study. See Note 3 under "Retail Regulatory Matters – Rate RSE" for additional information. (n) As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be established consistent with guidance provided by the Alabama PSC. See Note 5 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 and the Alabama PSC continuously monitor the under/over recovered balances. The Company 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 Compliance" 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. |
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. 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: 2017 2016 (in millions) Generation $ 14,213 $ 13,551 Transmission 4,119 3,921 Distribution 7,034 6,707 General 1,948 1,840 Plant acquisition adjustment 12 12 Total plant in service $ 27,326 $ 26,031 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 | 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 and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2017 , 3% in 2016 , and 2.9% in 2015 . Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by 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 2016, the Company submitted an updated depreciation study to the FERC and received authorization to use the recommended rates beginning January 2017. 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 AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. 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, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, 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, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, 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: 2017 2016 (in millions) Balance at beginning of year $ 1,533 $ 1,448 Liabilities incurred — 5 Liabilities settled (26 ) (25 ) Accretion 77 73 Cash flow revisions 125 32 Balance at end of year $ 1,709 $ 1,533 The increase in liabilities incurred and cash flow revisions in 2017 is primarily due to updated cost estimates related to the closure of ash ponds and landfills. The increase in 2016 is primarily related to changes in ash pond closure strategy. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. |
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, 2017 , investment securities in the Funds totaled $902 million , consisting of equity securities of $644 million , debt securities of $223 million , and $35 million of other securities. At December 31, 2016 , investment securities in the Funds totaled $790 million , consisting of equity securities of $552 million , debt securities of $208 million , and $30 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 $237 million , $351 million , and $438 million in 2017 , 2016 , and 2015 , respectively, all of which were reinvested. For 2017 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $125 million , which included $98 million related to unrealized gains on securities held in the Funds at December 31, 2017 . For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $76 million , which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million , which included $57 million related to unrealized losses on securities held in the Funds at December 31, 2015 . 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 through 2040 as 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: 2017 2016 (in millions) External trust funds $ 902 $ 790 Internal reserves 18 19 Total $ 920 $ 809 Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2017 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 completed 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 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, 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. |
Impairment of Long-Lived Assets | 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. |
Restricted Cash, 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 recorded 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 and Derivatives | 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 on the balance sheets (included in "Other") 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. 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. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 . The Company is exposed to potential 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 CO | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Georgia Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle Units 1 and 2, and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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. In 2015, the Company identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, the Company recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million . The Company evaluated the effects of this error on the interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, the Company determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to PPAs and cellular towers where the Company is the lessee and to outdoor lighting where the Company is the lessor. The Company is currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. |
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 $625 million , $606 million , and $585 million in 2017 , 2016 , and 2015 , 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. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment. 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 $675 million , $666 million , and $681 million in 2017 , 2016 , and 2015 , respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information. The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $235 million , $265 million , and $179 million in 2017 , 2016 , and 2015 , respectively. See Note 6 under "Capital Leases" and 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 $11 million , $8 million , and $12 million in 2017 , 2016 , and 2015 , respectively. See Note 4 for additional information. In 2014, prior to Southern Company's acquisition of PowerSecure on May 9, 2016, the Company entered into agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. In October 2016, the two facilities began commercial operation. Payments of $119 million made by the Company to PowerSecure under the agreements since 2014 are included in utility plant in service at December 31, 2017 . On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $102 million in 2017 and $35 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016 . Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $22 million in 2017 and $10 million for the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016 . 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 2017 , 2016 , or 2015 . The traditional electric 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 accounting requirements 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. |
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. |
Income and Other Taxes | fuel. 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, upon utilization, amortized to income as a credit to reduce depreciation over the average life of the related property. The Company had $87 million in federal ITCs at December 31, 2017 that will expire by 2037. State ITCs are recognized in the period in which the credits are generated. The Company had state investment and other tax credit carryforwards totaling $495 million at December 31, 2017 , which will expire between 2019 and 2028 and are expected to be fully utilized by 2026. 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 | ation. 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: 2017 2016 (in millions) Generation $ 17,038 $ 16,668 Transmission 5,947 5,779 Distribution 9,978 9,553 General 1,870 1,813 Plant acquisition adjustment 28 28 Total plant in service $ 34,861 $ 33,841 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, respec |
Depreciation 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 2017 , 2.8% in 2016 , and 2.7% in 2015 . 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. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual and recovery of other retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, amounts to be recovered are reflected in the balance sheets as a regulatory asset and any accumulated removal costs for future obligations are reflected in the balance sheets as a regulatory liability. The ARO liability primarily relates to the Company's ash ponds, landfills, and gypsum cells that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule). In addition, the Company has retirement obligations related to decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, 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: 2017 2016 (in millions) Balance at beginning of year $ 2,532 $ 1,916 Liabilities incurred 4 — Liabilities settled (120 ) (123 ) Accretion 89 77 Cash flow revisions 133 662 Balance at end of year $ 2,638 $ 2,532 In 2017 and 2016, the increases in cash flow revisions are primarily related to changes to the Company's closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities settled are primarily related to ash pond closure activity. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as nece |
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, 2017 and 2016 , approximately $76 million and $56 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 $77 million and $58 million at December 31, 2017 and 2016 , 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, 2017 , investment securities in the Funds totaled $929 million , consisting of equity securities of $415 million , debt securities of $502 million , and $12 million of other securities. At December 31, 2016 , investment securities in the Funds totaled $814 million , consisting of equity securities of $326 million , debt securities of $477 million , and $11 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 securities lending program. Sales of the securities held in the Funds resulted in cash proceeds of $568 million , $803 million , and $980 million in 2017 , 2016 , and 2015 , respectively, all of which were reinvested. For 2017 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $108 million , which included $83 million related to unrealized gains on securities held in the Funds at December 31, 2017 . For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $38 million , which included $14 million related to unrealized losses on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $3 million , which included $26 million related to unrealized gains and losses on securities held in the Funds at December 31, 2015 . 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 2015 . The site study costs and external trust funds for decommissioning as of December 31, 2017 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 2075 2079 (in millions) Site study costs: Radiated structures $ 678 $ 568 Spent fuel management 160 147 Non-radiated structures 64 89 Total site study costs $ 902 $ 804 External trust funds $ 583 $ 346 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 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 review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in the Company's 2019 base rate case. |
Allowance for Funds Used During Construction and Interest Capitalized | case. Allowance for Funds Used During Construction 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, 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 2017 , 2016 , and 2015 , the average AFUDC rates were 5.6% , 6.9% , and 6.5% , respectively, and AFUDC capitalized was $63 million , $68 million , and $56 million , respectively. AFUDC, net of income taxes, as a percentage of net income after dividends on preferred and preference stock was 3.8% , 4.6% , and 3.9% for 2017 , 2016 , and 2015 , 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 | 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 Reserves and Environmental Remediation Recovery | 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, 2017 and December 31, 2016 , the balance in the regulatory asset related to storm damage was $333 million and $206 million , respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $303 million and $176 million included in other regulatory assets, deferred, respectively. 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, costs related to storms are generally not expected to have a material impact on the Company's earnings. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information. Environmental Remediation Recovery The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable 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 earnings. As of December 31, 2017 , the balance of the environmental remediation liability was $22 million and is included in other current liabilities. As of December 31, 2017 , the balance of under recovered environmental remediation costs was $49 million , with approximately $2 million included in other regulatory assets, current and approximately $47 million included as other regulatory assets, deferred. As of December 31, 2016 , the balance of the environmental remediation liability was $17 million and is included in other current liabilities. As of December 31, 2016 , the balance of under recovered environmental remediation costs was $35 million , with approximately $2 million included in other regulatory assets, current and approximately $33 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information. |
Restricted Cash, 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 recorded 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 and Derivatives | 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 on the balance sheets (included in "Other") 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. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 . The Company is exposed to potential 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. 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 net 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 energy-related commodity prices. The Company manages a fuel-hedging program through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. At December 31, 2017 and 2016 , substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Effective January 1, 2016, the Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48 -month time horizon. Energy-related derivative contracts are accounted for under 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. |
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. |
Fair Value Measurement | 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 products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. 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' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information. 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. |
GULF POWER CO | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Gulf Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), Inc. (PowerSecure), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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 Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to a PPA, cellular towers, and barges where the Company is the lessee and to outdoor lighting and power distribution equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. |
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 $81 million , $80 million , and $81 million during 2017 , 2016 , and 2015 , 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. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment. 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 $11 million , $8 million , and $12 million and Mississippi Power $31 million , $26 million , and $27 million in 2017 , 2016 , and 2015 , respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. Total power purchased from affiliates through the power pool, included in purchased power in the statements of income, totaled $15 million , $16 million , and $35 million in 2017, 2016, and 2015, respectively. The Company has an agreement with Alabama Power under which Alabama Power made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. Payments by the Company to Alabama Power for the improvements were $11 million , $12 million , and $14 million in 2017 , 2016 , and 2015 , respectively, and are expected to be approximately $10 million annually for 2018 through 2023 , when the PPA expires. 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. In 2016, the Company purchased a turbine rotor assembly from Southern Power for $6.8 million . 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 2017 , 2016 , or 2015 . The traditional electric 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans, net $ 166 $ 160 (a,b) PPA charges 119 141 (b,c) Closure of ash ponds 80 75 (b,d) Remaining book value of retired assets 65 66 (e) Environmental remediation 52 44 (b,d) Other regulatory assets, net 36 18 (i) Deferred income tax charges 31 56 (f) Deferred return on transmission upgrades 25 25 (e) Fuel-hedging assets, net 21 24 (b,h) Loss on reacquired debt 17 18 (j) Asset retirement obligations, net 13 7 (b,f) Regulatory asset, offset to other cost of removal — 29 (e) Deferred income tax credits (458 ) (2 ) (g) Other cost of removal obligations (221 ) (278 ) (f) Property damage reserve (40 ) (40 ) (e) Over recovered regulatory clause revenues (11 ) (23 ) (k) Total regulatory assets (liabilities), net $ (105 ) $ 320 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) Not earning a return as offset in rate base by a corresponding asset or liability. (c) Recovered over the life of the PPA for periods up to six years . (d) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (e) Recorded and recovered or amortized as approved by the Florida PSC. (f) Asset retirement and removal assets and liabilities are recorded, and deferred income tax assets are recorded, recovered, and 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. (g) Deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years . Includes the deferred tax liabilities as a result of the Tax Reform Legislation. Amortization of $71 million of the deferred tax liabilities at December 31, 2017 is expected to be determined by the Florida PSC at a later date. See Notes 3 and 5 for additional information. (h) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which currently do not exceed four years . Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (i) Comprised primarily of under recovered regulatory clause revenues. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year . (j) 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 . (k) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . 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. 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: 2017 2016 (in millions) Generation $ 3,005 $ 3,001 Transmission 720 706 Distribution 1,282 1,241 General 188 191 Plant acquisition adjustment 1 1 Total plant in service $ 5,196 $ 5,140 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 and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% for all years presented. 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 in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), the Company was allowed to reduce depreciation and record a regulatory asset in an aggregate amount up to $62.5 million between January 2014 and June 2017. See Note 3 under "Retail Regulatory Matters – Retail Base Rate Cases" for additional information. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. 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 facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and to the closure of an ash pond at Plant Scholz. In addition, the Company has retirement obligations related to combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, 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 on the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 136 $ 130 Liabilities incurred — 1 Liabilities settled (8 ) (1 ) Accretion 2 4 Cash flow revisions 12 2 Balance at end of year $ 142 $ 136 The cost estimates for AROs related to CCR are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure for those facilities impacted by the CCR Rule. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction 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, 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 all years presented. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 0.07% , 0.00% , and 10.8% for 2017 , 2016 , and 2015 , respectively. |
Impairment of Long-Lived Assets | 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 Reserves and Environmental Remediation Recovery | 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 million and $55 million . In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), the Company suspended further property damage reserve accruals effective April 2017. The Company may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve falls below zero . The Company accrued total expenses of $3.5 million in each of 2017 , 2016 , and 2015 . As of December 31, 2017 and 2016 , the balance in the Company's property damage reserve totaled approximately $40 million , which is included in other regulatory liabilities, deferred on 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. As authorized in the 2017 Rate Case Settlement Agreement, the Company may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million ( 75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00 /month for a 1,000 KWH residential customer unless the Company incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million . See Note 3 under "Retail Regulatory Matters – Retail Base Rate Cases" for additional details of the 2017 Rate Case 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 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 had a balance of $2.1 million and $1.4 million at December 31, 2017 , and 2016 , respectively. For 2017, $1.6 million and $0.5 million are included in other current liabilities and other deferred credits and liabilities on the balance sheet, respectively. For 2016, the $1.4 million balance is included in other current liabilities on the balance sheet. There were no liabilities in excess of the reserve balance at December 31, 2017 or 2016 . |
Restricted Cash, 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 recorded 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 and Derivatives | 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 on the balance sheets (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. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. The Florida PSC extended the moratorium on the Company's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. See Note 10 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 . The Company is exposed to potential 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 CO | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Mississippi Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The Company is subject to regulation by the FERC and the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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 Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term , as well as longer-term contractual commitments, including PPAs. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. |
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 $140 million , $231 million , and $295 million during 2017 , 2016 , and 2015 , respectively. Cost allocation methodologies used by SCS prior to the repe al 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. See Note 7 under "Operating Leases" for additional information. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene Coun ty Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $9 million , $13 million , and $11 million in 2017 , 2016 , and 2015 , respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility. There were no fuel purchases in 2017 or 2016 . Fuel purchases were $8 million in 2015 . 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, whic h totaled $31 million , $26 million , and $27 million in 2017 , 2016 , and 2015 , respectively. See Note 4 for additional information. Total power purchased from affiliates through the power pool, included in purchased power in the statement of operations, totaled $16 million , $29 million , and $7 million in 2017 , 2016 , and 2015 , respectively. In June 2017, the Company received a capital contribution from Southern Company of $1.0 billion . The Company used a portion of the proceeds to repay all of the $591 million outstanding principal amount of promissory notes to Southern Company. See Note 6 for additional information. On September 15, 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible research and experimental (R&E) expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" 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 he rein, the Company neither provided nor received any material services to or from affiliates in 2017 , 2016 , or 2015 . The traditional electric operating companies, including the Company, and S outhern 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 accounting requirements 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: 2017 2016 Note (in millions) Retiree benefit plans – regulatory assets $ 174 $ 173 (a) Asset retirement obligations 95 83 (b) Kemper County energy facility 88 194 (c) Remaining net book value of retired assets 44 53 (d) Property tax 43 37 (e) Deferred charges related to income taxes 36 362 (d) Plant Daniel Units 3 and 4 36 33 (f) Other regulatory assets 28 28 (g) ECO carryforward 26 22 (h) Other regulatory liabilities — (1 ) (i) Deferred credits related to income taxes (377 ) (9 ) (j) Other cost of removal obligations (178 ) (170 ) (k) Property damage (57 ) (68 ) (l) Total regulatory assets (liabilities), net $ (42 ) $ 737 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) To be recovered upon completion of removal activities over a period approved by the Mississippi PSC. (c) Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered in rates over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." (d) Recovered over the related property lives up to 48 years. (e) Recovered through the ad valorem tax adjustment clause over a 12 -month period beg inning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. (f) Represents the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, which will be amortized over a 10 -year period beginning October 2021. (g) Comprised of vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. This amount also includes fuel-hedging assets and liabilities which 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 ECM. (h) Recovered through the ECO clause in the year following the deferral. (i) Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year. (j) This amount includes excess deferred income taxes primarily associated with Tax Reform Legislation of $375 million , of which $273 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $102 million related to unprotected (not subject to normalization) deferred income taxes to be amortized over a period approved by the Mississippi PSC or the FERC, as appropriate. Of the total excess deferred income taxes associated with Tax Reform Legislation, $129 million is associated with the Kemper County energy facility. The unprotected portion associated with the Kemper County energy facility is $54 million , of which $38 million is being amortized over eight years for retail as approved by the Mississippi PSC on February 6, 2018 and $16 million is wholesale-related. Currently, the Company is requesting eight -year amortization for the remaining portions of the unprotected deferred income taxes associated with Tax Reform Legislation in all of its retail and wholesale rate filings. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" and Note 5 for additional information. (k) Collected in advance from customers to remove assets upon their retirement. (l) For additional information, see Note 1 under "Provision for Property Damage." 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" and "Kemper County Energy Facility" for additional information. |
Government Grants | Government Grants In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants). Through December 31, 2017 , the Company has received grant funds of $382 million , of which $245 million of the Initial DOE Grants were used for the construction of the Kemper County energy facility, which is reflected in the Company's financial statements as a reduction to the Kemper County energy facility capital costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $2 million is expected to be received for allowable costs through December 31, 2017. See Note 3 under "Kemper County Energy Facility – 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 represent ed 19.3% of the Company's total operating revenues in 2017 and are largely subject to rolling 10 -year c ancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers. Except as described above for the Company's cost-based MRA electric tariff customers, the Company has a diversified base of customers and 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 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. T axes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. 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: 2017 2016 (in millions) Generation $ 2,801 $ 2,632 Transmission 737 712 Distribution 946 916 General 204 520 Plant acquisition adjustment 85 85 Total plant in service $ 4,773 $ 4,865 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 a portion of the railway track maintenance costs. The portion of railway track maintenance costs not charged to operations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. |
Depreciation and Amortization | Depreciation, Depletion, and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.7% in 2017 , 4.2% in 2016 , and 4.7% in 2015 . The decrease in 2017 is primarily due to lower depreciation expense as a result of recording a loss on the lignite mine in June 2017. The decrease in the 2016 depreciation rate is primarily due to fully depreciating and retiring the ARO at Plant Watson, partially offset by the increase in depreciation for the Plant Daniel scrubbers for a full year. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. The Mississippi PSC approved the 2014 study, with new rates effective January 1, 2015. 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, except for the Kemper County energy facility combined cycle and related assets in service. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. 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 liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations 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 and certain wireless communication towers. 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 th e 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 e ither a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. Details of the AROs included in the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 179 $ 177 Liabilities incurred — 15 Liabilities settled (23 ) (23 ) Accretion 5 5 Cash flow revisions 13 5 Balance at end of year $ 174 $ 179 The increase in cash flow revisions in 2017 is primarily related to a revision in the closure date of the lignite mine ARO. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction 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, 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. |
Impairment of Long-Lived Assets | 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 Reserves and Environmental Remediation Recovery | 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 exce ed $50,000 i s charged to the reserve. Every three years the Mississippi PSC, the 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. The Company made retail accruals of $3 million , $4 million , and $3 million for 2017 , 2016 , and 2015 , respectively. The Company also accrued $0.3 million annually in 2017 , 2016 , and 2015 for the wholesale jurisdiction. As of December 31, 2017 , the property damage reserve balances were $56 million and $1 million for retail and wholesa le, respectively. |
Restricted Cash, 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 used, at weighted-average cost when utilized. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel costs are recorded to inventory when purchased, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates. 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 and Derivatives | 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 on the balance sheets (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 that 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. 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. Cash flows from d erivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company's collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 are immaterial. 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 potential 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. 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 net 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 energy-related commodity prices. 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. Energy-related derivative contracts are accounted for under one of the following 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. • 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. |
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 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. |
Fair Value Measurement | 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. |
SOUTHERN POWER CO | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, and other direct and indirect subsidiaries. The traditional electric 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) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Effective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations. The Company adopted the same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis. The preparation of consolidated 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 consolidated financial statements have been reclassified to conform to the current year presentation. The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment. Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements. Other In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information. On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. |
Affiliate Transactions | Affiliate Transactions Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million , $258 million , and $219 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015 . The 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. Prior to December 2017, the Company did not have employees and thus all employee-related charges were rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS totaled $218 million , $193 million , and $146 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Of these costs, $192 million , $173 million , and $138 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. 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. Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015. The Company also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in fuel expense on the consolidated statements of income. On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $25 million for the year ended December 31, 2017 and $7 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016. The Company and the traditional electric 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 electric 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 | Acquisition Accounting The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred. Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 for additional fair value information. |
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. All capacity revenues are included in wholesale revenues. 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 additional information. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. Transmission revenues and other fees are recognized as earned as other operating revenues. 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 Company's top three customers for each of the years presented: 2017 2016 2015 Georgia Power 11.3 % 16.5 % 15.8 % Duke Energy Corporation 6.7 % 7.8 % 8.2 % Morgan Stanley Capital Group 4.5 % N/A N/A San Diego Gas & Electric Company N/A 5.7 % N/A Florida Power & Light Company N/A N/A 10.7 % |
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 current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs 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. In addition, certain projects are eligible for federal PTCs, which are recorded as an income tax benefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2017 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information. |
Property, Plant, and Equipment | Property, Plant, and Equipment The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, 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. When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income. |
Depreciation and Amortization | Depreciation The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are 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 generating facilities, which generally have estimated useful lives as follows: Generating facility Useful life Natural gas Up to 45 years Biomass Up to 40 years Solar Up to 35 years Wind Up to 30 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. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations Asset retirement obligations (ARO) are computed as the present value of the estimated 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. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 11 for acquisitions during 2017 and 2016 which contributed to the increased liability. |
Long-Term Service Agreements | Long-Term Service Agreements The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired 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 other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the consolidated statements of cash flows. |
Impairment of Long-Lived Assets | 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 primarily of certain PPAs acquired, which are amortized over the term of the PPAs, which have a weighted average term of 19 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. |
Transmission Receivables/Prepayments | Transmission Receivables/Prepayments As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five -year period and the receivable/prepayments are reduced as payments or services are received. |
Restricted Cash, Cash and Cash Equivalents | Restricted Cash The Company has restricted cash primarily related to certain acquisitions and construction projects. The aggregate amount of restricted cash at December 31, 2017 and 2016 was $11 million and $13 million , 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 | Materials and Supplies Materials and supplies include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment. |
Fuel Inventory | Fuel Inventory Fuel inventory, which is included in other current assets, includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several natural gas 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 also 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 and Derivatives | 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 foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other") 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. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 9 for additional information regarding derivatives. The Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 or 2016. The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has 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. The Company is exposed to market risks, primarily commodity price risk and interest rate risk, and occasionally foreign currency exchange 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 consolidated balance sheets as either assets or liabilities and are presented on a net basis. See Note 8 for additional fair value information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. The Company has limited exposure to market volatility in energy-related commodity prices 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. Energy-related derivative contracts are accounted for under 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 consolidated 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 consolidated 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. |
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 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. |
Fair Value Measurement | 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. |
SOUTHERN Co GAS | |
Summary of Significant Accounting Policies [Line Items] | |
General | General On July 1, 2016, Southern Company and Southern Company Gas (together with its subsidiaries, the Company) completed the Merger and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. In addition to the Company, Southern Company is the parent company of four traditional electric operating companies, Southern Power, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, Inc., and other direct and indirect subsidiaries. The Company is an energy services holding company whose primary business is the distribution of natural gas across seven states through its seven natural gas distribution utilities. The Company also is involved in several other businesses that are complementary to the distribution of natural gas. The traditional electric operating companies – Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power 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. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure, Inc. is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect the Company's investments in its subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for VIEs where the Company has an equity investment, but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The seven natural gas distribution utilities are subject to regulation by the regulatory agencies of each state in which they operate. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply 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. Pursuant to the Merger, Southern Company has pushed down the application of the acquisition method of accounting to the financial statements of the Company such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the financial statements of the Company for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout the financial statements and notes to the financial statements, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor." Certain predecessor period data presented in the financial statements has been modified or reclassified to conform to the presentation used by the Company's new parent company, Southern Company. Changes to the statements of income include classifying operating revenues as natural gas revenues and other revenues as well as classifying cost of goods sold as cost of natural gas and cost of other sales, and presenting interest expense and AFUDC on a gross basis. Changes to the statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each category of cash flow activity. Changes to the balance sheets include changing certain captions to conform to the presentation of Southern Company. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Revenue In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment. The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment . Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019. The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to real estate and fleet vehicles where the Company is the lessee and to natural gas home appliances where the Company is the lessor. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. Other In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note 5 for the disclosure impacted by ASU 2016-09. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. |
Affiliate Transactions | Affiliate Transactions SCS, as agent for Alabama Power, Georgia Power, and Southern Power, and the Company have long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and the Company by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the successor year ended December 31, 2017 , transportation revenue under these agreements from SCS and the Company were $136 million and $32 million , respectively. For the successor period of September 1, 2016 through December 31, 2016, transportation revenue under these agreements from SCS and the Company were $32 million and $15 million , respectively. See Note 4 under "Equity Method Investments – SNG" for additional information regarding the Company's investment in SNG. The Company has an agreement with SCS under which the following services are currently being rendered to the Company as direct or allocated cost: accounting, finance and treasury, tax, information technology, auditing, insurance and pension administration, human resources, systems and procedures, purchasing, and other services. For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 , costs for these services amounted to $63 million and $17 million , respectively. 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. SCS, as agent for Alabama Power, Georgia Power, and Southern Power, has agreements with certain subsidiaries of the Company to purchase natural gas. For the successor year ended December 31, 2017 , natural gas purchases made by SCS from the Company's subsidiaries were $142 million . For the successor period of July 1, 2016 through December 31, 2016 , natural gas purchases made by SCS from the Company's subsidiaries were $27 million . |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The Company is subject to accounting requirements 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: 2017 2016 Note (in millions) Environmental remediation $ 410 $ 411 (a,b) Retiree benefit plans 270 325 (a,c) Long-term debt fair value adjustment 138 154 (d) Under recovered regulatory clause revenues 98 118 (e) Other regulatory assets 79 58 (f) Other cost of removal obligations (1,646 ) (1,616 ) (g) Deferred income tax credits (1,063 ) (22 ) (g,i) Over recovered regulatory clause revenues (144 ) (104 ) (e) Other regulatory liabilities (21 ) (39 ) (h) Total regulatory assets (liabilities), net $ (1,879 ) $ (715 ) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Not earning a return as offset in rate base by a corresponding asset or liability. (b) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (c) Recovered and amortized over the average remaining service period which range up to 15 years . See Note 2 for additional information. (d) Recovered over the remaining life of the original debt issuances, which range up to 21 years . (e) Recorded and recovered or amortized as approved or accepted by the appropriate state regulatory agencies over periods generally not exceeding eight years . (f) Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, deferred depreciation expense, and financial instrument-hedging assets, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding 10 years , except for financial hedging-instruments. Financial instrument-hedging assets 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, and actual income earned is refunded through the energy cost recovery clause. (g) Other cost of removal obligations are recorded and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years . Cost of removal liabilities will be settled and trued up following completion of the related activities. (h) Comprised of several components including energy efficiency programs, unamortized bond issuance costs and financial instrument-hedging liabilities which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding a range of four years to 20 years , except for financial hedging-instruments. Financial instrument-hedging 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, and actual income earned is refunded through the energy cost recovery clause. (i) Includes excess deferred income tax liabilities not subject to normalization as a result of the Tax Reform Legislation, the recovery and amortization of which will be determined by the applicable state regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional details. In the event that a portion of a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the natural gas distribution utility 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 "Regulatory Matters" for additional information |
Revenues | . Revenues Gas Distribution Operations The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the Company's utilities. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. All of the natural gas distribution utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period. The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, so long as the amounts recognized will be collected from customers within 24 months of recognition. These programs are as follows: • Weather normalization adjustments – reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas, Elizabethtown Gas, and Chattanooga Gas; • Revenue normalization mechanisms – mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas, Chattanooga Gas, and Elkton Gas; and • Revenue true-up adjustment – included within the provisions of the Georgia Rate Adjustment Mechanism (GRAM) program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a monthly positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year. Revenue Taxes The Company charges customers for gas revenue and gas use taxes imposed on the Company and remits amounts owed to various governmental authorities. Gas revenue taxes are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on the Company are recorded as operating expenses on the statements of income. Gas use taxes are excluded from revenue and expense with the related administrative fee included in operating revenues when the tax is imposed on the customer. Revenue taxes included in operating expenses were $98 million and $31 million for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 , respectively, and $56 million and $101 million for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 , respectively. Gas Marketing Services The Company recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. The Company also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period. The Company recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. Revenues for warranty and repair contracts are recognized on a straight-line basis over the contract term while revenues for maintenance services are recognized at the time such services are performed. Wholesale Gas Services The Company nets revenues from energy and risk management activities with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. The Company records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue. Concentration of Revenue 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. |
Cost Of Natural Gas | Cost of Natural Gas and Other Sales Gas Distribution Operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the Company charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively. Gas Marketing Services The Company's gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, the Company also includes costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives. The Company records the costs to service its warranty and repair contract claims as cost of other sales. |
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 on the balance sheet, excluding revenue taxes which are presented on the statements of income. See "Revenues – Gas Distribution Operations – Revenue Taxes" herein for additional information. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. |
Property, Plant, and Equipment | Property, Plant, and Equipment Property, plant, and equipment is stated at original cost, or fair value at the effective date of the Merger as appropriate, 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: 2017 2016 (in millions) Utility plant in service $ 13,079 $ 11,996 Information technology equipment and software 366 324 Storage facilities 1,599 1,463 Other 789 725 Total other plant in service 2,754 2,512 Total plant in service $ 15,833 $ 14,508 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. The portion of non-working gas used to maintain the structural integrity of the Company's natural gas storage facilities that is considered to be non-recoverable is recorded as depreciable property, plant, and equipment, while the recoverable or retained portion is recorded as non-depreciable property, plant, and equipment. The amount of non-cash property additions recognized for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $135 million , $63 million , $41 million , and $48 million , respectively. These amounts are comprised of construction-related accounts payable outstanding at the end of each period. |
Depreciation and Amortization | Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.9% in 2017 , 2.8% in 2016 , and 2.7% in 2015 . Depreciation studies are conducted periodically to update the composite rates that are approved by the respective state regulatory agency. 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 asset are retired when the related property unit is retired. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over the following useful lives: five to 15 years for transportation equipment, 40 to 60 years for storage facilities, and up to 65 years for other assets. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction The Company records AFUDC for Atlanta Gas Light, Nicor Gas, Chattanooga Gas, and Elizabethtown Gas, 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, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The capital expenditures of the other three natural gas utilities do not qualify for AFUDC treatment. The Company's AFUDC composite rates are as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Atlanta Gas Light 8.10 % 4.05 % 4.05 % 8.10 % Chattanooga Gas 7.41 3.71 3.71 7.41 Elizabethtown Gas (*) 1.56 0.84 0.84 1.69 Nicor Gas (*) 1.22 1.50 1.50 0.82 (*) Variable rate is determined by the FERC method of AFUDC accounting. Cash payments for interest during the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 totaled $223 million , $135 million , $119 million , and $181 million , respectively. |
Restricted Cash, 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. |
Energy Marketing Receivables and Payables | Energy Marketing Receivables and Payables Wholesale gas services provides services to retail gas marketers, wholesale gas marketers, utility companies, and industrial customers. These counterparties utilize netting agreements that enable wholesale gas services to net receivables and payables by counterparty upon settlement. Wholesale gas services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale gas services' counterparties are settled net, they are recorded on a gross basis in the balance sheets as energy marketing receivables and energy marketing payables. Wholesale gas services has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if the Company's credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale gas services would need to post collateral to continue transacting business with some of its counterparties. As of December 31, 2017 and 2016 , the required collateral in the event of a credit rating downgrade was $8 million and immaterial, respectively. Wholesale gas services has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. Counterparty credit risk is evaluated using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody's rating to an internal rating ranging from 9 to 1 , with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being equivalent to D/Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2017 , the top 20 counterparties represented 48% , or $203 million , of the total counterparty exposure and had a weighted average S&P equivalent rating of A-. Credit policies were established to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale gas services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of the Company's credit risk. Wholesale gas services also uses other netting agreements with certain counterparties with whom it conducts significant transactions. |
Receivables and Allowance for Uncollectible Accounts | . Receivables and Provision for Uncollectible Accounts The Company's other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer's inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible. Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include propane gas inventory, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. |
Natural Gas for Sale | Natural Gas for Sale The natural gas distribution utilities, with the exception of Nicor Gas, record natural gas inventories on a WACOG basis. In Georgia's competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. Nicor Gas' inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on the Company's net income. At December 31, 2017 , the Nicor Gas LIFO inventory balance was $148 million . Based on the average cost of gas purchased in December 2017 , the estimated replacement cost of Nicor Gas' inventory at December 31, 2017 was $264 million . During 2017 , Nicor Gas did not liquidate any LIFO-based inventory. The gas marketing services, wholesale gas services, and all other segments record inventory at LOCOM, with cost determined on a WACOG basis. For these segments, the Company evaluates the weighted average cost of its natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, the Company recorded the following LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. |
Fair Value Measurements | Fair Value Measurements The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. The nonfinancial assets and liabilities include pension and other postretirement benefits. See Notes 2 and 9 for additional fair value disclosures. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows: Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company's Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets. Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include shorter tenor exchange-traded and non-exchange-traded derivatives such as over-the-counter (OTC) forwards and options and certain retirement plan assets. Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management's best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company's pension and other postretirement benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred. |
Financial Instruments and Derivatives | Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, weather, interest rates, and commodity prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved 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. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 . The Company enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the statements of income. Wholesale gas services purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price that can be received in the future, resulting in positive net natural gas revenues. NYMEX futures and OTC contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. The Company enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the balance sheets, with changes in fair value recorded in natural gas revenues on the statements of income in the period of change. These contracts are not designated as hedges for accounting purposes. The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated. The Company is exposed to potential 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 | Non-Wholly Owned Entities The Company holds ownership interests in a number of business ventures with varying ownership structures and evaluates all of its partnership interests and other variable interests to determine if each entity is a VIE. If a venture is a VIE for which the Company is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. The Company reassesses its conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. See Note 4 under "Variable Interest Entities" for additional information. For entities that are not determined to be VIEs, the Company evaluates whether it has control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of the Company are consolidated, and entities over which the Company can exert significant influence, but does not control, are accounted for under the equity method of accounting. However, the Company also invests in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless the interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures. Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries within the other property and investments section in the balance sheets and the equity income is recorded within earnings from equity method investments within the other income (expense) section in the statements of income. |
Summary of Significant Accoun31
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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: 2017 2016 Note (in millions) Retiree benefit plans $ 3,931 $ 3,959 (a,n) Asset retirement obligations-asset 1,133 1,080 (b,n) Deferred income tax charges 814 1,590 (b,p) Environmental remediation-asset 511 491 (j,n) Property damage reserves-asset 333 206 (i) Under recovered regulatory clause revenues 317 273 (g) Remaining net book value of retired assets 306 351 (o) Loss on reacquired debt 223 243 (c) Vacation pay 183 182 (f,n) Long-term debt fair value adjustment 138 155 (d) Deferred PPA charges 119 141 (e,n) Kemper County energy facility 88 201 (h) Other regulatory assets 511 487 (k) Deferred income tax credits (7,261 ) (219 ) (b,p) Other cost of removal obligations (2,684 ) (2,774 ) (b) Over recovered regulatory clause revenues (155 ) (203 ) (g) Property damage reserves-liability (135 ) (177 ) (l) Other regulatory liabilities (266 ) (120 ) (m) Total regulatory assets (liabilities), net $ (1,894 ) $ 5,866 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 other cost of removal obligations 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 80 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (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) Recovered over the remaining life of the original debt issuances, which range up to 21 years . For additional information see Note 12 under " Southern Company – Merger with Southern Company Gas ." (e) Recovered over the life of the PPA for periods up to six 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 or other applicable regulatory agencies over periods generally not exceeding 10 years . (h) Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years , respectively. For additional information, see Note 3 under " Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement ." (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under " Regulatory Matters – Georgia Power – Storm Damage Recovery " for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years . (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years . (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 48 years . (p) As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under " Regulatory Matters " and Note 5 for additional information. |
Property Plant and Equipment | The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: 2017 2016 (in millions) Electric utilities: Generation $ 51,279 $ 48,836 Transmission 11,562 11,156 Distribution 19,239 18,418 General 4,276 4,629 Plant acquisition adjustment 126 126 Electric utility plant in service 86,482 83,165 Natural gas distribution utilities: Transportation and distribution 13,078 11,996 Utility plant in service 99,560 95,161 Information technology equipment and software 752 544 Communications equipment 456 424 Storage facilities 1,598 1,463 Other 1,176 824 Total other plant in service 3,982 3,255 Total plant in service $ 103,542 $ 98,416 |
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, 2017 2016 (in millions) Office buildings $ 216 $ 61 Nitrogen plant (*) — 83 Computer-related equipment 51 63 Gas pipeline 6 6 Less: Accumulated amortization (72 ) (69 ) Balance, net of amortization $ 201 $ 144 (*) Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information. |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 4,514 $ 3,759 Liabilities incurred 16 66 Liabilities settled (177 ) (171 ) Accretion 179 162 Cash flow revisions 292 698 Balance at end of year $ 4,824 $ 4,514 |
Accumulated Provisions for Decommissioning | At December 31, 2017 and 2016 , the accumulated provisions for the external decommissioning trust funds were as follows: External Trust Funds 2017 2016 (in millions) Plant Farley $ 902 $ 790 Plant Hatch 583 511 Plant Vogtle Units 1 and 2 346 303 |
Estimated Cost of Decommissioning | The estimated costs of decommissioning as of December 31, 2017 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 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 2075 2079 (in millions) Site study costs: Radiated structures $ 1,362 $ 678 $ 568 Spent fuel management — 160 147 Non-radiated structures 80 64 89 Total site study costs $ 1,442 $ 902 $ 804 |
Schedule of Finite-Lived and Infinite-Lived Intangible Assets | At December 31, 2017 and 2016 , other intangible assets were as follows: At December 31, 2017 At December 31, 2016 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Gross Carrying Amount Accumulated Amortization Other (in millions) (in millions) Other intangible assets subject to amortization: Customer relationships 11-26 years $ 288 $ (83 ) $ 205 $ 268 $ (32 ) $ 236 Trade names 5-28 years 159 (17 ) 142 158 (5 ) 153 Storage and transportation contracts 1-5 years 64 (34 ) 30 64 (2 ) 62 PPA fair value adjustments 10-20 years 456 (47 ) 409 456 (22 ) 434 Other 1-12 years 17 (5 ) 12 11 (1 ) 10 Total other intangible assets subject to amortization $ 984 $ (186 ) $ 798 $ 957 $ (62 ) $ 895 Other intangible assets not subject to amortization: Federal Communications Commission licenses 75 — 75 75 — 75 Total other intangible assets $ 1,059 $ (186 ) $ 873 $ 1,032 $ (62 ) $ 970 |
Future Amortization Expense for Intangible Assets | As of December 31, 2017 , the estimated amortization associated with other intangible assets for the next five years is as follows: Amortization (in millions) 2018 $ 95 2019 77 2020 65 2021 56 2022 51 |
Future Amortization Expense for Intangible Liabilities | The remaining estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: Amortization (in millions) 2018 $ 24 2019 17 |
Net Investments in Leveraged Leases | Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31: 2017 2016 (in millions) Net rentals receivable $ 1,498 $ 1,481 Unearned income (723 ) (707 ) Investment in leveraged leases 775 774 Deferred taxes from leveraged leases (252 ) (309 ) Net investment in leveraged leases $ 523 $ 465 |
Components of Income from Leveraged Leases | A summary of the components of income from the leveraged leases follows: 2017 2016 2015 (in millions) Pretax leveraged lease income $ 25 $ 25 $ 20 Net impact of Tax Reform Legislation 48 — — Income tax expense (9 ) (9 ) (7 ) Net leveraged lease income $ 64 $ 16 $ 13 |
Accumulated Other Comprehensive Income (Loss) Balances, Net of Tax Effects | Accumulated OCI (loss) balances, net of tax effects, were as follows: Qualifying Hedges Pension and Other Postretirement Benefit Plans Accumulated Other Comprehensive Income (Loss) (in millions) Balance at December 31, 2016 $ (115 ) $ (65 ) $ (180 ) Current period change (4 ) (5 ) (9 ) Balance at December 31, 2017 $ (119 ) $ (70 ) $ (189 ) |
ALABAMA POWER CO | |
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: 2017 2016 Note (in millions) Retiree benefit plans $ 946 $ 947 (i,j) Deferred income tax charges 240 526 (a,k,n) Regulatory clauses 142 — (m) Vacation pay 70 69 (c,j) Loss on reacquired debt 62 68 (b) Nuclear outage 56 70 (d) Remaining net book value of retired assets 54 69 (l) Under/(over) recovered regulatory clause revenues 53 76 (d) Other regulatory assets 51 50 (f) Fuel-hedging losses 7 1 (e,j) Deferred income tax credits (2,082 ) (65 ) (a,n) Other cost of removal obligations (609 ) (684 ) (a) Natural disaster reserve (38 ) (69 ) (h) Asset retirement obligations (33 ) 12 (a) Other regulatory liabilities (7 ) (23 ) (e,g) Total regulatory assets (liabilities), net $ (1,088 ) $ 1,047 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 credits are amortized over the related property lives, which may range up to 50 years . Asset retirement and other cost of 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 . See Note 3 under "Retail Regulatory Matters" for additional information. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half 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 (to be recovered over the next 12 months ), 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 fuel-hedging gains. 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 $13 million for 2017 and $16 million for 2016 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 up to 11 years . (m) Established per an order from the Alabama PSC issued on February 17, 2017 and will be amortized concurrently with the effective date of the Company's next depreciation study. See Note 3 under "Retail Regulatory Matters – Rate RSE" for additional information. (n) As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be established consistent with guidance provided by the Alabama PSC. See Note 5 for additional information. |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2017 2016 (in millions) Generation $ 14,213 $ 13,551 Transmission 4,119 3,921 Distribution 7,034 6,707 General 1,948 1,840 Plant acquisition adjustment 12 12 Total plant in service $ 27,326 $ 26,031 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 1,533 $ 1,448 Liabilities incurred — 5 Liabilities settled (26 ) (25 ) Accretion 77 73 Cash flow revisions 125 32 Balance at end of year $ 1,709 $ 1,533 |
Accumulated Provisions for Decommissioning | At December 31, the accumulated provisions for decommissioning were as follows: 2017 2016 (in millions) External trust funds $ 902 $ 790 Internal reserves 18 19 Total $ 920 $ 809 |
Estimated Cost of Decommissioning | The estimated costs of decommissioning as of December 31, 2017 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 CO | |
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: 2017 2016 Note (in millions) Retiree benefit plans, net $ 166 $ 160 (a,b) PPA charges 119 141 (b,c) Closure of ash ponds 80 75 (b,d) Remaining book value of retired assets 65 66 (e) Environmental remediation 52 44 (b,d) Other regulatory assets, net 36 18 (i) Deferred income tax charges 31 56 (f) Deferred return on transmission upgrades 25 25 (e) Fuel-hedging assets, net 21 24 (b,h) Loss on reacquired debt 17 18 (j) Asset retirement obligations, net 13 7 (b,f) Regulatory asset, offset to other cost of removal — 29 (e) Deferred income tax credits (458 ) (2 ) (g) Other cost of removal obligations (221 ) (278 ) (f) Property damage reserve (40 ) (40 ) (e) Over recovered regulatory clause revenues (11 ) (23 ) (k) Total regulatory assets (liabilities), net $ (105 ) $ 320 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) Not earning a return as offset in rate base by a corresponding asset or liability. (c) Recovered over the life of the PPA for periods up to six years . (d) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (e) Recorded and recovered or amortized as approved by the Florida PSC. (f) Asset retirement and removal assets and liabilities are recorded, and deferred income tax assets are recorded, recovered, and 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. (g) Deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years . Includes the deferred tax liabilities as a result of the Tax Reform Legislation. Amortization of $71 million of the deferred tax liabilities at December 31, 2017 is expected to be determined by the Florida PSC at a later date. See Notes 3 and 5 for additional information. (h) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which currently do not exceed four years . Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (i) Comprised primarily of under recovered regulatory clause revenues. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year . (j) 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 . (k) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2017 2016 (in millions) Generation $ 3,005 $ 3,001 Transmission 720 706 Distribution 1,282 1,241 General 188 191 Plant acquisition adjustment 1 1 Total plant in service $ 5,196 $ 5,140 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included on the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 136 $ 130 Liabilities incurred — 1 Liabilities settled (8 ) (1 ) Accretion 2 4 Cash flow revisions 12 2 Balance at end of year $ 142 $ 136 |
GEORGIA POWER CO | |
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: 2017 2016 Note (in millions) Retiree benefit plans $ 1,313 $ 1,348 (a, k) Asset retirement obligations 945 893 (b, k) Deferred income tax charges 521 681 (b, c, k) Storm damage reserves 333 206 (d) Remaining net book value of retired assets 146 166 (e) Loss on reacquired debt 127 137 (f, k) Other regulatory assets 119 97 (g) Vacation pay 91 91 (h, k) Other cost of removal obligations 40 3 (b) Cancelled construction projects 36 44 (i) Deferred income tax credits (3,248 ) (121 ) (b, c) Other regulatory liabilities (191 ) (39 ) (j, k) Total regulatory assets (liabilities), net $ 232 $ 3,506 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) 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 65 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $21 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022. (c) As a result of Tax Reform Legislation, these balances include $145 million of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 and $626 million of deferred income tax liabilities, neither of which are subject to normalization. The recovery and amortization of these amounts will be determined by the Georgia PSC. See Note 3 under "Retail Regulatory Matters – Rate Plans" and Note 5 for additional information. (d) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information. (e) Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. The net book value of Plant Mitchell Unit 3 at December 31, 2017 was $10 million , which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $4 million , and $31 million related to obsolete inventories of certain retired units is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information. (f) 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 35 years . (g) Comprised of several components including deferred nuclear outages, environmental remediation, building lease, demand-side management tariff under-recovery, and fuel-hedging losses. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months . The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $54 million at December 31, 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. Fuel-hedging losses are recovered through the Company's fuel cost recovery mechanism upon final settlement. (h) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (i) 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. (j) Comprised of certain customer refunds and fuel-hedging gains. As ordered by the Georgia PSC on January 11, 2018, approximately $188 million of the proceeds pursuant to the Toshiba Guarantee will be refunded to customers in 2018. Fuel-hedging gains are refunded through the Company's fuel cost recovery mechanism upon final settlement. See Note 3 under "Nuclear Construction" for additional information on the customer refunds related to the Toshiba Guarantee. (k) 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: 2017 2016 (in millions) Generation $ 17,038 $ 16,668 Transmission 5,947 5,779 Distribution 9,978 9,553 General 1,870 1,813 Plant acquisition adjustment 28 28 Total plant in service $ 34,861 $ 33,841 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 2,532 $ 1,916 Liabilities incurred 4 — Liabilities settled (120 ) (123 ) Accretion 89 77 Cash flow revisions 133 662 Balance at end of year $ 2,638 $ 2,532 |
Accumulated Provisions for Decommissioning | The site study costs and external trust funds for decommissioning as of December 31, 2017 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 2075 2079 (in millions) Site study costs: Radiated structures $ 678 $ 568 Spent fuel management 160 147 Non-radiated structures 64 89 Total site study costs $ 902 $ 804 External trust funds $ 583 $ 346 |
MISSISSIPPI POWER CO | |
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: 2017 2016 Note (in millions) Retiree benefit plans – regulatory assets $ 174 $ 173 (a) Asset retirement obligations 95 83 (b) Kemper County energy facility 88 194 (c) Remaining net book value of retired assets 44 53 (d) Property tax 43 37 (e) Deferred charges related to income taxes 36 362 (d) Plant Daniel Units 3 and 4 36 33 (f) Other regulatory assets 28 28 (g) ECO carryforward 26 22 (h) Other regulatory liabilities — (1 ) (i) Deferred credits related to income taxes (377 ) (9 ) (j) Other cost of removal obligations (178 ) (170 ) (k) Property damage (57 ) (68 ) (l) Total regulatory assets (liabilities), net $ (42 ) $ 737 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) To be recovered upon completion of removal activities over a period approved by the Mississippi PSC. (c) Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered in rates over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." (d) Recovered over the related property lives up to 48 years. (e) Recovered through the ad valorem tax adjustment clause over a 12 -month period beg inning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. (f) Represents the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, which will be amortized over a 10 -year period beginning October 2021. (g) Comprised of vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. This amount also includes fuel-hedging assets and liabilities which 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 ECM. (h) Recovered through the ECO clause in the year following the deferral. (i) Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year. (j) This amount includes excess deferred income taxes primarily associated with Tax Reform Legislation of $375 million , of which $273 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $102 million related to unprotected (not subject to normalization) deferred income taxes to be amortized over a period approved by the Mississippi PSC or the FERC, as appropriate. Of the total excess deferred income taxes associated with Tax Reform Legislation, $129 million is associated with the Kemper County energy facility. The unprotected portion associated with the Kemper County energy facility is $54 million , of which $38 million is being amortized over eight years for retail as approved by the Mississippi PSC on February 6, 2018 and $16 million is wholesale-related. Currently, the Company is requesting eight -year amortization for the remaining portions of the unprotected deferred income taxes associated with Tax Reform Legislation in all of its retail and wholesale rate filings. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" and Note 5 for additional information. (k) Collected in advance from customers to remove assets upon their retirement. (l) For additional information, see Note 1 under "Provision for Property Damage." |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2017 2016 (in millions) Generation $ 2,801 $ 2,632 Transmission 737 712 Distribution 946 916 General 204 520 Plant acquisition adjustment 85 85 Total plant in service $ 4,773 $ 4,865 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 179 $ 177 Liabilities incurred — 15 Liabilities settled (23 ) (23 ) Accretion 5 5 Cash flow revisions 13 5 Balance at end of year $ 174 $ 179 |
SOUTHERN POWER CO | |
Summary of Significant Accounting Policies [Line Items] | |
Property Plant and Equipment | The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows: Generating facility Useful life Natural gas Up to 45 years Biomass Up to 40 years Solar Up to 35 years Wind Up to 30 years |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included on the consolidated balance sheets are as follows: 2017 2016 (in millions) Balance at beginning of year $ 64 $ 21 Liabilities incurred 6 42 Accretion 4 1 Cash flow revisions 4 — Balance at end of year $ 78 $ 64 |
Future Amortization Expense for Intangible Assets | The estimated annual amortization expense is $25 million for each of the next five years. |
Accumulated Other Comprehensive Income (Loss) Balances, Net of Tax Effects | Accumulated OCI (loss) balances, net of tax effects, were as follows: Qualifying Hedges Pension and Other Postretirement Benefit Plans Accumulated Other Comprehensive Income (Loss) (in millions) Balance at December 31, 2016 $ 35 $ — $ 35 Current period change (10 ) — (10 ) Other comprehensive income transfer from SCS (*) — (27 ) (27 ) Balance at December 31, 2017 $ 25 $ (27 ) $ (2 ) (*) In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of OCI, net of tax of $9 million , was transferred from SCS. |
Schedule of Revenue by Major Customers by Reporting Segments | The following table shows the percentage of total revenues for the Company's top three customers for each of the years presented: 2017 2016 2015 Georgia Power 11.3 % 16.5 % 15.8 % Duke Energy Corporation 6.7 % 7.8 % 8.2 % Morgan Stanley Capital Group 4.5 % N/A N/A San Diego Gas & Electric Company N/A 5.7 % N/A Florida Power & Light Company N/A N/A 10.7 % |
SOUTHERN Co GAS | |
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: 2017 2016 Note (in millions) Environmental remediation $ 410 $ 411 (a,b) Retiree benefit plans 270 325 (a,c) Long-term debt fair value adjustment 138 154 (d) Under recovered regulatory clause revenues 98 118 (e) Other regulatory assets 79 58 (f) Other cost of removal obligations (1,646 ) (1,616 ) (g) Deferred income tax credits (1,063 ) (22 ) (g,i) Over recovered regulatory clause revenues (144 ) (104 ) (e) Other regulatory liabilities (21 ) (39 ) (h) Total regulatory assets (liabilities), net $ (1,879 ) $ (715 ) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Not earning a return as offset in rate base by a corresponding asset or liability. (b) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (c) Recovered and amortized over the average remaining service period which range up to 15 years . See Note 2 for additional information. (d) Recovered over the remaining life of the original debt issuances, which range up to 21 years . (e) Recorded and recovered or amortized as approved or accepted by the appropriate state regulatory agencies over periods generally not exceeding eight years . (f) Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, deferred depreciation expense, and financial instrument-hedging assets, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding 10 years , except for financial hedging-instruments. Financial instrument-hedging assets 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, and actual income earned is refunded through the energy cost recovery clause. (g) Other cost of removal obligations are recorded and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years . Cost of removal liabilities will be settled and trued up following completion of the related activities. (h) Comprised of several components including energy efficiency programs, unamortized bond issuance costs and financial instrument-hedging liabilities which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding a range of four years to 20 years , except for financial hedging-instruments. Financial instrument-hedging 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, and actual income earned is refunded through the energy cost recovery clause. (i) Includes excess deferred income tax liabilities not subject to normalization as a result of the Tax Reform Legislation, the recovery and amortization of which will be determined by the applicable state regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional details. |
Property Plant and Equipment | . The Company's property, plant, and equipment in service consisted of the following at December 31: 2017 2016 (in millions) Utility plant in service $ 13,079 $ 11,996 Information technology equipment and software 366 324 Storage facilities 1,599 1,463 Other 789 725 Total other plant in service 2,754 2,512 Total plant in service $ 15,833 $ 14,508 |
Schedule of Finite-Lived and Infinite-Lived Intangible Assets | Goodwill and other intangible assets consisted of the following: At December 31, 2017 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Intangible Assets, Net (in millions) Other intangible assets subject to amortization: Gas marketing services Customer relationships 11-16 years $ 221 $ (77 ) $ 144 Trade names 10-28 years 115 (9 ) 106 Wholesale gas services Storage and transportation contracts 1-5 years 64 (34 ) 30 Total intangible assets subject to amortization $ 400 $ (120 ) $ 280 Goodwill: Gas distribution operations $ 4,702 $ — $ 4,702 Gas marketing services 1,265 — 1,265 Total goodwill $ 5,967 $ — $ 5,967 At December 31, 2016 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Intangible Assets, Net (in millions) Other intangible assets subject to amortization: Gas marketing services Customer relationships 11-16 years $ 221 $ (30 ) $ 191 Trade names 10-28 years 115 (2 ) 113 Wholesale gas services Storage and transportation contracts 1-5 years 64 (2 ) 62 Total intangible assets subject to amortization $ 400 $ (34 ) $ 366 Goodwill: Gas distribution operations $ 4,702 $ — $ 4,702 Gas marketing services 1,265 — 1,265 Total goodwill $ 5,967 $ — $ 5,967 |
Future Amortization Expense for Intangible Assets | As of December 31, 2017 , the estimated amortization associated with other intangible assets is as follows: Amortization (in millions) 2018 $ 58 2019 40 2020 28 2021 21 2022 17 |
Future Amortization Expense for Intangible Liabilities | The estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: Amortization (in millions) 2018 $ 24 2019 17 |
Schedule of Inventory, Lower of Cost or Market Adjustment | For any declines considered to be other than temporary, the Company recorded the following LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. Successor Predecessor 2017 July 1, 2016 to December 31, 2016 January 1, 2016 to June 30, 2016 2015 (in millions) (in millions) Gas marketing services $ — $ — $ — $ 3 Wholesale gas services 2 1 3 19 All other — — — 1 Total LOCOM adjustments $ 2 $ 1 $ 3 $ 23 |
Composite AFUDC Rates | SOUTHERN Co GAS | |
Summary of Significant Accounting Policies [Line Items] | |
Property Plant and Equipment | The Company's AFUDC composite rates are as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Atlanta Gas Light 8.10 % 4.05 % 4.05 % 8.10 % Chattanooga Gas 7.41 3.71 3.71 7.41 Elizabethtown Gas (*) 1.56 0.84 0.84 1.69 Nicor Gas (*) 1.22 1.50 1.50 0.82 (*) Variable rate is determined by the FERC method of AFUDC accounting. |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.40 % 4.58 % 4.17 % Discount rate – interest costs 3.77 3.88 4.17 Discount rate – service costs 4.81 4.98 4.48 Expected long-term return on plan assets 7.92 8.16 8.20 Annual salary increase 4.37 4.37 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.23 % 4.38 % 4.04 % Discount rate – interest costs 3.54 3.66 4.04 Discount rate – service costs 4.64 4.85 4.39 Expected long-term return on plan assets 6.84 6.66 6.97 Annual salary increase 4.37 4.37 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.80 % 4.40 % Annual salary increase 4.32 4.37 Other postretirement benefit plans Discount rate 3.68 % 4.23 % Annual salary increase 4.32 4.37 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 |
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, 2017 as follows: 1 Percent 1 Percent (in millions) Benefit obligation $ 132 $ 113 Service and interest costs 4 3 |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 12,385 $ 10,542 Acquisitions — 1,244 Service cost 293 262 Interest cost 455 422 Benefits paid (596 ) (466 ) Plan amendments (26 ) 39 Actuarial (gain) loss 1,297 342 Balance at end of year 13,808 12,385 Change in plan assets Fair value of plan assets at beginning of year 11,583 9,234 Acquisitions — 837 Actual return (loss) on plan assets 1,953 902 Employer contributions 52 1,076 Benefits paid (596 ) (466 ) Fair value of plan assets at end of year 12,992 11,583 Accrued liability $ (816 ) $ (802 ) |
Schedule of amounts recognized in other comprehensive income (loss) | 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, 2017 and 2016 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2015 $ 8 $ 411 Net (gain) loss (1 ) (13 ) Reclassification adjustments: Amortization of prior service costs — (6 ) Amortization of net gain (loss) — (14 ) Total reclassification adjustments — (20 ) Total change (1 ) (33 ) Balance at December 31, 2016 $ 7 $ 378 Net (gain) loss (3 ) (21 ) Change in prior service costs — 3 Reclassification adjustments: Amortization of prior service costs — (6 ) Amortization of net gain (loss) — (13 ) Total reclassification adjustments — (19 ) Total change (3 ) (37 ) Balance at December 31, 2017 $ 4 $ 341 |
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, 2017 and 2016 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 2018 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ 3 $ 104 Regulatory assets 14 3,140 Total $ 17 $ 3,244 Balance at December 31, 2016: Accumulated OCI $ 4 $ 96 Regulatory assets 51 3,069 Total $ 55 $ 3,165 Estimated amortization in net periodic pension cost in 2018: Accumulated OCI $ 1 $ 9 Regulatory assets 4 204 Total $ 5 $ 213 |
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, 2017 and 2016 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2015 $ 125 $ 2,998 Net (gain) loss (20 ) 243 Change in prior service costs 2 37 Reclassification adjustments: Amortization of prior service costs (1 ) (13 ) Amortization of net gain (loss) (6 ) (145 ) Total reclassification adjustments (7 ) (158 ) Total change (25 ) 122 Balance at December 31, 2016 $ 100 $ 3,120 Net (gain) loss 15 227 Change in prior service costs — (26 ) Reclassification adjustments: Amortization of prior service costs (1 ) (11 ) Amortization of net gain (loss) (7 ) (155 ) Total reclassification adjustments (8 ) (166 ) Total change 7 35 Balance at December 31, 2017 $ 107 $ 3,155 |
Estimated pension benefit payments | At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 634 2019 637 2020 663 2021 681 2022 704 2023 to 2027 3,836 |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,297 $ 1,989 Acquisitions — 338 Service cost 24 22 Interest cost 79 76 Benefits paid (136 ) (119 ) Actuarial (gain) loss 65 (16 ) Plan amendments 3 — Retiree drug subsidy 7 7 Balance at end of year 2,339 2,297 Change in plan assets Fair value of plan assets at beginning of year 944 833 Acquisitions — 100 Actual return (loss) on plan assets 154 58 Employer contributions 84 65 Benefits paid (129 ) (112 ) Fair value of plan assets at end of year 1,053 944 Accrued liability $ (1,286 ) $ (1,353 ) |
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, 2017 and 2016 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 2018 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ — $ 4 Net regulatory assets 21 320 Total $ 21 $ 324 Balance at December 31, 2016: Accumulated OCI $ — $ 7 Net regulatory assets 25 353 Total $ 25 $ 360 Estimated amortization as net periodic postretirement benefit cost in 2018: Net regulatory assets $ 7 $ 14 |
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 Payments Subsidy Receipts Total (in millions) 2018 $ 144 $ (7 ) $ 137 2019 148 (8 ) 140 2020 151 (8 ) 143 2021 154 (9 ) 145 2022 156 (9 ) 147 2023 to 2027 780 (48 ) 732 |
Composition of benefit plan assets along with targeted mix of assets | The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016 , along with the targets, is presented below: Target 2017 2016 Pension plan assets: Equity 53 % 65 % 69 % Fixed Income 15 19 20 Cash 2 6 1 Other 30 10 10 Balance at end of period 100 % 100 % 100 % The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016 , along with the targets, is presented below: Target 2017 2016 Other postretirement benefit plan assets: Equity 72 % 76 % 74 % Fixed Income 24 20 23 Cash 1 2 1 Other 3 2 2 Total 100 % 100 % 100 % A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below: Description Valuation Methodology ● 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. Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. ● Fixed income: A mix of domestic and international bonds. 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. ● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. ● 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 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. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. |
Pension plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 3,273 $ 3,207 Other current liabilities (53 ) (53 ) Employee benefit obligations (763 ) (749 ) Other regulatory liabilities, deferred (118 ) (87 ) Accumulated OCI 107 100 |
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 293 $ 262 $ 257 Interest cost 455 422 445 Expected return on plan assets (897 ) (782 ) (724 ) Recognized net (gain) loss 162 150 215 Net amortization 12 14 25 Net periodic pension cost $ 25 $ 66 $ 218 |
Other postretirement benefit plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 382 $ 419 Other current liabilities (5 ) (4 ) Employee benefit obligations (1,281 ) (1,349 ) Other regulatory liabilities, deferred (41 ) (41 ) Accumulated OCI 4 7 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 24 $ 22 $ 23 Interest cost 79 76 78 Expected return on plan assets (66 ) (60 ) (58 ) Net amortization 20 21 21 Net periodic postretirement benefit cost $ 57 $ 59 $ 64 |
Fair values of benefit plan assets | The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Total Target Allocation Actual Allocation As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 132 $ 35 $ — $ — $ 167 37 % 40 % International equity (*) 47 76 — — 123 23 23 Fixed income: 30 29 U.S. Treasury, government, and agency bonds — 32 — — 32 Corporate bonds — 37 — — 37 Pooled funds — 55 — — 55 Cash equivalents and other 10 — — — 10 Trust-owned life insurance — 426 — — 426 Real estate investments 16 — — 36 52 5 5 Special situations — — — 5 5 1 1 Private equity — — — 20 20 4 2 Total $ 205 $ 661 $ — $ 61 $ 927 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 118 $ 28 $ — $ — $ 146 39 % 40 % International equity (*) 37 61 — — 98 23 21 Fixed income: 29 31 U.S. Treasury, government, and agency bonds — 24 — — 24 Corporate bonds — 30 — — 30 Pooled funds — 49 — — 49 Cash equivalents and other 41 — — — 41 Trust-owned life insurance — 382 — — 382 Real estate investments 11 — — 35 46 5 5 Special situations — — — 5 5 1 1 Private equity — — — 17 17 3 2 Total $ 207 $ 574 $ — $ 57 $ 838 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
ALABAMA POWER CO | |
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 net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.44 % 4.67 % 4.18 % Discount rate – interest costs 3.76 3.90 4.18 Discount rate – service costs 4.85 5.07 4.49 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.27 % 4.51 % 4.04 % Discount rate – interest costs 3.58 3.69 4.04 Discount rate – service costs 4.70 4.96 4.40 Expected long-term return on plan assets 6.83 6.83 7.17 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.81 % 4.44 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.71 % 4.27 % Annual salary increase 4.46 4.46 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 |
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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 30 $ 26 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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,663 $ 2,506 Service cost 63 57 Interest cost 98 95 Benefits paid (120 ) (109 ) Actuarial (gain) loss 294 114 Balance at end of year 2,998 2,663 Change in plan assets Fair value of plan assets at beginning of year 2,517 2,279 Actual return (loss) on plan assets 427 206 Employer contributions 12 141 Benefits paid (120 ) (109 ) Fair value of plan assets at end of year 2,836 2,517 Accrued liability $ (162 ) $ (146 ) |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 63 $ 86 Other regulatory liabilities, deferred (7 ) (10 ) Employee benefit obligations (111 ) (134 ) Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 890 $ 870 Other current liabilities (12 ) (12 ) Employee benefit obligations (150 ) (134 ) |
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, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 11 $ 15 $ 4 Net (gain) loss 45 61 1 Net regulatory assets $ 56 $ 76 Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 8 $ 10 $ 1 Net (gain) loss 882 860 54 Regulatory assets $ 890 $ 870 |
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, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 870 $ 822 Net (gain) loss 64 84 Change in prior service costs — 7 Reclassification adjustments: Amortization of prior service costs (2 ) (3 ) Amortization of net gain (loss) (42 ) (40 ) Total reclassification adjustments (44 ) (43 ) Total change 20 48 Ending balance $ 890 $ 870 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Net regulatory assets (liabilities): Beginning balance $ 76 $ 82 Net (gain) loss (15 ) — Reclassification adjustments: Amortization of prior service costs (4 ) (4 ) Amortization of net gain (loss) (1 ) (2 ) Total reclassification adjustments (5 ) (6 ) Total change (20 ) (6 ) Ending balance $ 56 $ 76 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 6 $ 5 $ 6 Interest cost 17 18 20 Expected return on plan assets (25 ) (25 ) (26 ) Net amortization 5 6 5 Net periodic postretirement benefit cost $ 3 $ 4 $ 5 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 63 $ 57 $ 59 Interest cost 98 95 106 Expected return on plan assets (196 ) (184 ) (178 ) Recognized net (gain) loss 42 40 55 Net amortization 2 3 6 Net periodic pension cost $ 9 $ 11 $ 48 |
Estimated pension benefit payments | At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 129 2019 134 2020 139 2021 143 2022 148 2023 to 2027 807 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 Payments Subsidy Receipts Total (in millions) 2018 $ 31 $ (2 ) $ 29 2019 32 (2 ) 30 2020 33 (3 ) 30 2021 34 (3 ) 31 2022 35 (3 ) 32 2023 to 2027 173 (14 ) 159 |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 501 $ 505 Service cost 6 5 Interest cost 17 18 Benefits paid (29 ) (28 ) Actuarial (gain) loss 20 (1 ) Retiree drug subsidy 2 2 Balance at end of year 517 501 Change in plan assets Fair value of plan assets at beginning of year 367 363 Actual return (loss) on plan assets 60 23 Employer contributions 6 7 Benefits paid (27 ) (26 ) Fair value of plan assets at end of year 406 367 Accrued liability $ (111 ) $ (134 ) |
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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 42 % 44 % 44 % International equity 22 22 20 Domestic fixed income 28 28 29 Special situations 1 — 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 other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 52 $ 12 $ — $ — $ 64 International equity (*) 16 14 — — 30 Fixed income: U.S. Treasury, government, and agency bonds — 11 — — 11 Corporate bonds — 12 — — 12 Pooled funds — 7 — — 7 Cash equivalents and other 2 — — — 2 Trust-owned life insurance — 253 — — 253 Real estate investments 5 — — 12 17 Special situations — — — 2 2 Private equity — — — 7 7 Total $ 75 $ 309 $ — $ 21 $ 405 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 51 $ 10 $ — $ — $ 61 International equity (*) 13 12 — — 25 Fixed income: U.S. Treasury, government, and agency bonds — 7 — — 7 Corporate bonds — 10 — — 10 Pooled funds — 5 — — 5 Cash equivalents and other 14 — — — 14 Trust-owned life insurance — 220 — — 220 Real estate investments 4 — — 12 16 Special situations — — — 2 2 Private equity — — — 6 6 Total $ 82 $ 264 $ — $ 20 $ 366 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 572 $ 276 $ — $ — $ 848 International equity (*) 370 333 — — 703 Fixed income: U.S. Treasury, government, and agency bonds — 200 — — 200 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 286 — — 286 Pooled funds — 155 — — 155 Cash equivalents and other 51 3 — — 54 Real estate investments 111 — — 283 394 Special situations — — — 43 43 Private equity — — — 159 159 Total $ 1,104 $ 1,255 $ — $ 485 $ 2,844 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 477 $ 220 $ — $ — $ 697 International equity (*) 292 264 — — 556 Fixed income: U.S. Treasury, government, and agency bonds — 140 — — 140 Mortgage- and asset-backed securities — 3 — — 3 Corporate bonds — 235 — — 235 Pooled funds — 124 — — 124 Cash equivalents and other 236 1 — — 237 Real estate investments 74 — — 274 348 Special situations — — — 43 43 Private equity — — — 130 130 Total $ 1,079 $ 987 $ — $ 447 $ 2,513 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
GEORGIA POWER CO | |
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 net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.40 % 4.65 % 4.18 % Discount rate – interest costs 3.72 3.86 4.18 Discount rate – service costs 4.83 5.03 4.49 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.23 % 4.49 % 4.03 % Discount rate – interest costs 3.55 3.67 4.03 Discount rate – service costs 4.63 4.88 4.39 Expected long-term return on plan assets 6.79 6.27 6.48 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.79 % 4.40 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.68 % 4.23 % Annual salary increase 4.46 4.46 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 |
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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 59 $ 50 Service and interest costs 2 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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 3,800 $ 3,615 Service cost 74 70 Interest cost 138 136 Benefits paid (187 ) (164 ) Actuarial (gain) loss 363 143 Balance at end of year 4,188 3,800 Change in plan assets Fair value of plan assets at beginning of year 3,621 3,196 Actual return (loss) on plan assets 610 288 Employer contributions 14 301 Benefits paid (187 ) (164 ) Fair value of plan assets at end of year 4,058 3,621 Accrued liability $ (130 ) $ (179 ) |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 202 $ 213 Employee benefit obligations (477 ) (493 ) Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Prepaid pension costs $ 23 $ — Other regulatory assets, deferred 1,105 1,129 Other current liabilities (15 ) (14 ) Employee benefit obligations (138 ) (165 ) |
Schedule of amounts recognized in other comprehensive income (loss) | The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 213 $ 223 Net (gain) loss (2 ) — Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (8 ) (9 ) Total reclassification adjustments (9 ) (10 ) Total change (11 ) (10 ) Ending balance $ 202 $ 213 |
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, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 14 $ 17 $ 2 Net (gain) loss 1,091 1,112 69 Regulatory assets $ 1,105 $ 1,129 Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 5 $ 6 $ 1 Net (gain) loss 197 207 9 Regulatory assets $ 202 $ 213 |
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, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 1,129 $ 1,076 Net (gain) loss 36 99 Change in prior service costs — 14 Reclassification adjustments: Amortization of prior service costs (3 ) (5 ) Amortization of net gain (loss) (57 ) (55 ) Total reclassification adjustments (60 ) (60 ) Total change (24 ) 53 Ending balance $ 1,105 $ 1,129 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 7 $ 6 $ 7 Interest cost 29 30 34 Expected return on plan assets (25 ) (22 ) (24 ) Net amortization 9 10 11 Net periodic postretirement benefit cost $ 20 $ 24 $ 28 Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 74 $ 70 $ 73 Interest cost 138 136 154 Expected return on plan assets (283 ) (258 ) (251 ) Recognized net (gain) loss 57 55 76 Net amortization 3 5 9 Net periodic pension cost $ (11 ) $ 8 $ 61 |
Estimated pension benefit payments | At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 196 2019 201 2020 207 2021 210 2022 216 2023 to 2027 1,156 |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 847 $ 854 Service cost 7 6 Interest cost 29 30 Benefits paid (51 ) (45 ) Actuarial (gain) loss 28 (1 ) Retiree drug subsidy 3 3 Balance at end of year 863 847 Change in plan assets Fair value of plan assets at beginning of year 354 358 Actual return (loss) on plan assets 54 21 Employer contributions 26 17 Benefits paid (48 ) (42 ) Fair value of plan assets at end of year 386 354 Accrued liability $ (477 ) $ (493 ) |
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 Payments Subsidy Receipts Total (in millions) 2018 $ 55 $ (3 ) $ 52 2019 55 (3 ) 52 2020 56 (3 ) 53 2021 57 (4 ) 53 2022 58 (4 ) 54 2023 to 2027 288 (21 ) 267 |
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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 36 % 38 % 35 % International equity 24 24 24 Domestic fixed income 33 31 35 Special situations 1 1 1 Real estate investments 4 4 4 Private equity 2 2 1 Total 100 % 100 % 100 % |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 819 $ 394 $ — $ — $ 1,213 International equity (*) 529 477 — — 1,006 Fixed income: U.S. Treasury, government, and agency bonds — 286 — — 286 Mortgage- and asset-backed securities — 3 — — 3 Corporate bonds — 409 — — 409 Pooled funds — 221 — — 221 Cash equivalents and other 74 4 — — 78 Real estate investments 160 — — 404 564 Special situations — — — 61 61 Private equity — — — 228 228 Total $ 1,582 $ 1,794 $ — $ 693 $ 4,069 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 686 $ 317 $ — $ — $ 1,003 International equity (*) 420 380 — — 800 Fixed income: U.S. Treasury, government, and agency bonds — 201 — — 201 Mortgage- and asset-backed securities — 4 — — 4 Corporate bonds — 338 — — 338 Pooled funds — 179 — — 179 Cash equivalents and other 340 1 — — 341 Real estate investments 106 — — 394 500 Special situations — — — 61 61 Private equity — — — 188 188 Total $ 1,552 $ 1,420 $ — $ 643 $ 3,615 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 53 $ 11 $ — $ — $ 64 International equity (*) 14 46 — — 60 Fixed income: U.S. Treasury, government, and agency bonds — 6 — — 6 Corporate bonds — 11 — — 11 Pooled funds — 41 — — 41 Cash equivalents and other 4 — — — 4 Trust-owned life insurance — 173 — — 173 Real estate investments 6 — — 11 17 Special situations — — — 2 2 Private equity — — — 6 6 Total $ 77 $ 288 $ — $ 19 $ 384 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 45 $ 9 $ — $ — $ 54 International equity (*) 11 37 — — 48 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Corporate bonds — 9 — — 9 Pooled funds — 38 — — 38 Cash equivalents and other 15 — — — 15 Trust-owned life insurance — 162 — — 162 Real estate investments 3 — — 11 14 Special situations — — — 2 2 Private equity — — — 5 5 Total $ 74 $ 260 $ — $ 18 $ 352 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
GULF POWER CO | |
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 net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.46 % 4.71 % 4.18 % Discount rate – interest costs 3.82 3.97 4.18 Discount rate – service costs 4.81 5.04 4.48 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.25 % 4.51 % 4.04 % Discount rate – interest costs 3.56 3.68 4.04 Discount rate – service costs 4.62 4.88 4.38 Expected long-term return on plan assets 7.81 8.05 8.07 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.82 % 4.46 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.69 % 4.25 % Annual salary increase 4.46 4.46 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 |
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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 4 $ 3 Service and interest costs — — |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 517 $ 480 Service cost 13 12 Interest cost 19 19 Benefits paid (20 ) (17 ) Actuarial (gain) loss 58 23 Balance at end of year 587 517 Change in plan assets Fair value of plan assets at beginning of year 491 420 Actual return (loss) on plan assets 81 39 Employer contributions 1 49 Benefits paid (20 ) (17 ) Fair value of plan assets at end of year 553 491 Accrued liability $ (34 ) $ (26 ) |
Schedule of amounts recognized in other comprehensive income (loss) | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Net regulatory assets (liabilities): Beginning balance $ 7 $ 5 Net (gain) loss (1 ) 2 Ending balance $ 6 $ 7 |
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, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 2 $ 3 $ — Net (gain) loss 158 150 10 Regulatory assets $ 160 $ 153 |
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, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 153 $ 142 Net (gain) loss 15 16 Change in prior service costs — 2 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (7 ) (6 ) Total reclassification adjustments (8 ) (7 ) Total change 7 11 Ending balance $ 160 $ 153 |
Estimated pension benefit payments | At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 22 2019 23 2020 25 2021 26 2022 28 2023 to 2027 155 |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 83 $ 81 Service cost 1 1 Interest cost 3 3 Benefits paid (5 ) (4 ) Actuarial (gain) loss 1 2 Balance at end of year 83 83 Change in plan assets Fair value of plan assets at beginning of year 18 17 Actual return (loss) on plan assets 3 2 Employer contributions 4 3 Benefits paid (5 ) (4 ) Fair value of plan assets at end of year 20 18 Accrued liability $ (63 ) $ (65 ) |
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 Payments Subsidy Receipts Total (in millions) 2018 $ 5 $ — $ 5 2019 5 — 5 2020 5 — 5 2021 6 (1 ) 5 2022 6 (1 ) 5 2023 to 2027 28 (2 ) 26 |
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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 25 % 30 % 28 % International equity 24 24 21 Domestic fixed income 25 26 31 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % |
GULF POWER CO | Pension plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized on the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 160 $ 153 Other current liabilities (1 ) (1 ) Employee benefit obligations (33 ) (25 ) |
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 13 $ 12 $ 12 Interest cost 19 19 20 Expected return on plan assets (38 ) (34 ) (32 ) Recognized net (gain) loss 7 6 9 Net amortization 1 1 1 Net periodic pension cost $ 2 $ 4 $ 10 |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 112 $ 54 $ — $ — $ 166 International equity (*) 72 65 — — 137 Fixed income: U.S. Treasury, government, and agency bonds — 39 — — 39 Corporate bonds — 57 — — 57 Pooled funds — 30 — — 30 Cash equivalents and other 10 — — — 10 Real estate investments 22 — — 55 77 Special situations — — — 8 8 Private equity — — — 31 31 Total $ 216 $ 245 $ — $ 94 $ 555 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 93 $ 43 $ — $ — $ 136 International equity (*) 57 52 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 27 — — 27 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 47 — — 47 Pooled funds — 24 — — 24 Cash equivalents and other 46 — — — 46 Real estate investments 14 — — 53 67 Special situations — — — 8 8 Private equity — — — 25 25 Total $ 210 $ 194 $ — $ 86 $ 490 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
GULF POWER CO | Other postretirement benefit plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized on the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 8 $ 11 Other current liabilities (1 ) (1 ) Other regulatory liabilities, deferred (2 ) (4 ) Employee benefit obligations (62 ) (64 ) |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (1 ) (1 ) (1 ) Net periodic postretirement benefit cost $ 3 $ 3 $ 3 |
Fair values of benefit plan assets | The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 — — — 1 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 8 $ 8 $ — $ 3 $ 19 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 2 $ — $ — $ 5 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 8 $ 8 $ — $ 3 $ 19 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
MISSISSIPPI POWER CO | |
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 net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below. Assumptions used to determine net periodic costs: 2017 2016 2015 Pension plans Discount rate – benefit obligations 4.44 % 4.69 % 4.17 % Discount rate – interest costs 3.81 3.97 4.17 Discount rate – service costs 4.83 5.04 4.49 Expected long-term return on plan assets 7.95 8.20 8.20 Annual salary increase 4.46 4.46 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.22 % 4.47 % 4.03 % Discount rate – interest costs 3.55 3.66 4.03 Discount rate – service costs 4.65 4.88 4.38 Expected long-term return on plan assets 6.88 7.07 7.23 Annual salary increase 4.46 4.46 3.59 Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.80 % 4.44 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 3.68 % 4.22 % Annual salary increase 4.46 4.46 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 |
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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 5 $ 5 Service and interest costs — — |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 534 $ 500 Service cost 15 13 Interest cost 20 19 Benefits paid (22 ) (20 ) Actuarial (gain) loss 55 22 Balance at end of year 602 534 Change in plan assets Fair value of plan assets at beginning of year 499 430 Actual return (loss) on plan assets 84 39 Employer contributions 2 50 Benefits paid (22 ) (20 ) Fair value of plan assets at end of year 563 499 Accrued liability $ (39 ) $ (35 ) |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 18 $ 21 Other regulatory liabilities, deferred (1 ) (2 ) Employee benefit obligations (72 ) (74 ) |
Schedule of amounts recognized in other comprehensive income (loss) | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Net regulatory assets (liabilities): Beginning balance $ 19 $ 18 Net (gain) loss (1 ) 2 Reclassification adjustments: Amortization of net gain (loss) (1 ) (1 ) Total reclassification adjustments (1 ) (1 ) Total change (2 ) 1 Ending balance $ 17 $ 19 |
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, 2017 and 2016 are presented in the following table: 2017 2016 (in millions) Regulatory assets: Beginning balance $ 154 $ 144 Net (gain) loss 12 16 Change in prior service costs — 2 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (7 ) (7 ) Total reclassification adjustments (8 ) (8 ) Total change 4 10 Ending balance $ 158 $ 154 |
Estimated pension benefit payments | At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 23 2019 24 2020 26 2021 27 2022 28 2023 to 2027 164 |
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, 2017 and 2016 were as follows: 2017 2016 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 97 $ 97 Service cost 1 1 Interest cost 3 3 Benefits paid (6 ) (6 ) Actuarial (gain) loss 1 1 Retiree drug subsidy 1 1 Balance at end of year 97 97 Change in plan assets Fair value of plan assets at beginning of year 23 23 Actual return (loss) on plan assets 3 1 Employer contributions 4 4 Benefits paid (5 ) (5 ) Fair value of plan assets at end of year 25 23 Accrued liability $ (72 ) $ (74 ) |
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 Payments Subsidy Receipts Total (in millions) 2018 $ 6 $ — $ 6 2019 6 — 6 2020 6 (1 ) 5 2021 7 (1 ) 6 2022 7 (1 ) 6 2023 to 2027 34 (2 ) 32 |
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, 2017 and 2016 , along with the targeted mix of assets for each plan, is presented below: Target 2017 2016 Pension plan assets: Domestic equity 26 % 31 % 29 % International equity 25 25 22 Fixed income 23 24 29 Special situations 3 1 2 Real estate investments 14 13 13 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 21 % 25 % 23 % International equity 21 20 18 Domestic fixed income 37 38 43 Special situations 2 1 2 Real estate investments 12 11 10 Private equity 7 5 4 Total 100 % 100 % 100 % |
MISSISSIPPI POWER CO | Pension plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 158 $ 154 Other current liabilities (3 ) (3 ) Employee benefit obligations (36 ) (32 ) |
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, 2017 and 2016 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 2018 . 2017 2016 Estimated Amortization in 2018 (in millions) Prior service cost $ 3 $ 3 $ — Net (gain) loss 155 151 10 Regulatory assets $ 158 $ 154 |
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: 2017 2016 2015 (in millions) Service cost $ 15 $ 13 $ 13 Interest cost 20 19 21 Expected return on plan assets (40 ) (35 ) (33 ) Recognized net (gain) loss 7 7 10 Net amortization 1 1 1 Net periodic pension cost $ 3 $ 5 $ 12 |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 113 $ 55 $ — $ — $ 168 International equity (*) 73 66 — — 139 Fixed income: U.S. Treasury, government, and agency bonds — 40 — — 40 Corporate bonds — 56 — — 56 Pooled funds — 31 — — 31 Cash equivalents and other 10 1 — — 11 Real estate investments 22 — — 56 78 Special situations — — — 9 9 Private equity — — — 32 32 Total $ 218 $ 249 $ — $ 97 $ 564 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 95 $ 44 $ — $ — $ 139 International equity (*) 58 51 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 28 — — 28 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 46 — — 46 Pooled funds — 25 — — 25 Cash equivalents and other 47 — — — 47 Real estate investments 15 — — 54 69 Special situations — — — 8 8 Private equity — — — 26 26 Total $ 215 $ 195 $ — $ 88 $ 498 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
MISSISSIPPI POWER CO | Other postretirement benefit plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2017 2016 2015 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 4 Expected return on plan assets (1 ) (1 ) (2 ) Net amortization 1 1 1 Net periodic postretirement benefit cost $ 4 $ 4 $ 4 |
Fair values of benefit plan assets | The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 3 2 — — 5 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 — — — 1 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 9 $ 12 $ — $ 3 $ 24 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 9 $ 12 $ — $ 3 $ 24 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
SOUTHERN POWER CO | |
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 the benefit obligations for the pension and other postretirement plans as of the December 31, 2017 measurement date are presented below. Assumptions used to determine benefit obligations: 2017 Pension plans Discount rate 3.94 % Annual salary increase 4.46 Other postretirement benefit plans Discount rate 3.81 % Annual salary increase 4.46 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2026 Post-65 medical 5.00 4.50 2026 Post-65 prescription 10.00 4.50 2026 |
Schedule of amounts recognized in other comprehensive income (loss) | Presented below are the amounts included in AOCI at December 31, 2017 related to the Company's pension plan that had not yet been recognized in net periodic pension cost, along with the estimated amortization of such amounts for 2018. 2017 Estimated Amortization in 2018 (in millions) Prior service cost $ 1 $ — Net (gain) loss 32 2 AOCI $ 33 The APBO for the other postretirement benefit plan at December 31, 2017 is $11 million . Amounts recognized in the balance sheet at December 31, 2017 related to the Company's other postretirement benefit plan consist of the following: 2017 (in millions) Employee benefit obligations (included in other deferred credits and liabilities) $ (11 ) AOCI 3 Presented below are the amounts included in AOCI at December 31, 2017 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 2018. 2017 Estimated Amortization in 2018 (in millions) Net (gain) loss $ 3 $ — AOCI $ 3 |
Composition of benefit plan assets along with targeted mix of assets | The composition of the Company's pension plan assets as of December 31, 2017 , along with the targeted mix of assets for the plan, is presented below: Target 2017 Pension plan assets: Domestic equity 26 % 31 % International equity 25 25 Fixed income 23 24 Special situations 3 1 Real estate investments 14 13 Private equity 9 6 Total 100 % 100 % |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2017 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 28 $ 13 $ — $ — $ 41 International equity (*) 18 16 — — 34 Fixed income: U.S. Treasury, government, and agency bonds — 10 — — 10 Corporate bonds — 14 — — 14 Pooled funds — 8 — — 8 Cash equivalents and other 2 — — — 2 Real estate investments 5 — — 14 19 Special situations — — — 2 2 Private equity — — — 8 8 Total $ 53 $ 61 $ — $ 24 $ 138 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
SOUTHERN Co GAS | |
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 net periodic costs for the pension and other postretirement benefit plans for all periods presented and the benefit obligations as of the measurement date are presented below. Successor Predecessor Assumptions used to determine net periodic costs: Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Pension plans Discount rate – interest costs (a) 3.76 % 3.21 % 4.00 % 4.20 % Discount rate – service costs (a) 4.64 4.07 4.80 4.20 Expected long-term return on plan assets 7.60 7.75 7.80 7.80 Annual salary increase 3.50 3.50 3.70 3.70 Pension band increase (b) N/A 2.00 2.00 2.00 Other postretirement benefit plans Discount rate – interest costs (a) 3.40 % 2.84 % 3.60 % 4.00 % Discount rate – service costs (a) 4.55 3.96 4.70 4.00 Expected long-term return on plan assets 6.03 5.93 6.60 7.80 Annual salary increase 3.50 3.50 3.70 3.70 (a) Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate. (b) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates in accordance with the union agreements. Assumptions used to determine benefit obligations: 2017 2016 Pension plans Discount rate 3.74 % 4.39 % Annual salary increase 2.88 3.50 Pension band increase (*) N/A 2.00 Other postretirement benefit plans Discount rate 3.62 % 4.15 % Annual salary increase 2.56 3.50 (*) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates in accordance with the union agreements. |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.40 % 4.50 % 2038 Post-65 medical 7.80 4.50 2038 Post-65 prescription 7.80 4.50 2038 |
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, 2017 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 11 $ (10 ) Service and interest costs — — |
Changes in projected benefit obligations and fair value of plan assets | Changes in the projected benefit obligations and the fair value of plan assets for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 1,133 $ 1,244 ` $ 1,067 Service cost 23 15 13 Interest cost 42 20 21 Plan amendments (26 ) — — Benefits paid (91 ) (31 ) (26 ) Actuarial (gain) loss 103 (115 ) 169 Balance at end of period 1,184 1,133 1,244 Change in plan assets Fair value of plan assets at beginning of period 983 837 ` 847 Actual return (loss) on plan assets 175 48 15 Employer contributions 1 129 1 Benefits paid (91 ) (31 ) (26 ) Fair value of plan assets at end of period 1,068 983 837 Accrued liability $ 116 $ 150 $ 407 |
Schedule of amounts recognized in other comprehensive income (loss) | The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for all periods presented were as follows: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2015: $ 282 $ 88 Reclassification adjustments: Amortization of prior service costs 1 — Amortization of net loss (9 ) (4 ) Total reclassification adjustments (8 ) (4 ) Total change (8 ) (4 ) Predecessor – Balance at June 30, 2016: $ 274 $ 84 Successor – Balance at July 1, 2016: $ — $ 368 Net (gain) loss (43 ) (87 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (15 ) Total reclassification adjustments — (14 ) Total change (43 ) (101 ) Successor – Balance at December 31, 2016: $ (43 ) $ 267 Net (gain) loss 1 (31 ) Reclassification adjustments: Amortization of regulatory assets — (1 ) Amortization of net loss — (18 ) Total reclassification adjustments — (19 ) Total change 1 (50 ) Successor – Balance at December 31, 2017: $ (42 ) $ 217 The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for all periods presented were as follows: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2015: $ 36 $ 30 Net (gain) loss — — Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss (1 ) (1 ) Total reclassification adjustments (1 ) — Total change (1 ) — Predecessor – Balance at June 30, 2016: $ 35 $ 30 Successor – Balance at July 1, 2016: $ — $ 77 Net (gain) loss (3 ) (23 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (3 ) Total reclassification adjustments — (2 ) Total change (3 ) (25 ) Successor – Balance at December 31, 2016: $ (3 ) $ 52 Net (gain) loss — (5 ) Reclassification adjustments: Amortization of prior service costs — 3 Amortization of net loss — (4 ) Total reclassification adjustments — (1 ) Total change — (6 ) Successor – Balance at December 31, 2017: $ (3 ) $ 46 |
Components of net periodic benefit cost | Components of net periodic pension costs for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) Service cost $ 23 $ 15 $ 13 $ 28 Interest cost 42 20 21 45 Expected return on plan assets (70 ) (35 ) (33 ) (65 ) Amortization of regulatory assets 1 — — — Amortization: Prior service costs — (1 ) (1 ) (2 ) Net (gain)/loss 18 14 13 31 Net periodic pension cost $ 14 $ 13 $ 13 $ 37 |
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets | Changes in the APBO and the fair value of plan assets for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 308 $ 338 $ 318 Service cost 2 1 1 Interest cost 10 5 5 Benefits paid (19 ) (11 ) (11 ) Actuarial (gain) loss 3 (26 ) 24 Plan amendments 3 — — Employee contributions 3 1 1 Balance at end of period 310 308 338 Change in plan assets Fair value of plan assets at beginning of period 105 100 99 Actual return (loss) on plan assets 20 4 1 Employee contributions 3 1 1 Employer contributions 17 11 10 Benefits paid (20 ) (11 ) (11 ) Fair value of plan assets at end of year 125 105 100 Accrued liability $ 185 $ 203 $ 238 |
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 regulatory assets at December 31, 2017 and 2016 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 2018 . Regulatory Amortization Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ — $ — $ (42 ) Regulatory assets (liabilities) 40 (20 ) 197 Total $ 40 $ (20 ) $ 155 Balance at December 31, 2016: Accumulated OCI $ — $ — $ (43 ) Regulatory assets (liabilities) — (2 ) 269 Total $ — $ (2 ) $ 226 Estimated amortization in net periodic cost in 2018: Regulatory assets (liabilities) $ 3 $ (2 ) $ 16 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is immaterial. Regulatory Amortization Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2017: Accumulated OCI $ — $ — $ (3 ) Regulatory assets (liabilities) 6 (7 ) 47 Total $ 6 $ (7 ) $ 44 Balance at December 31, 2016: Accumulated OCI $ — $ — $ (3 ) Regulatory assets (liabilities) — (12 ) 64 Total $ — $ (12 ) $ 61 |
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, 2017 and 2016 , along with the targets for each plan, is presented below: Target 2017 2016 Pension plan assets: Equity 53 % 65 % 69 % Fixed Income 15 19 20 Cash 2 6 1 Other 30 10 10 Balance at end of period 100 % 100 % 100 % Other postretirement benefit plan assets: Equity 72 % 76 % 74 % Fixed Income 24 20 23 Cash 1 2 1 Other 3 2 2 Total 100 % 100 % 100 % |
Fair values of benefit plan assets | Special situations (absolute return and hedge funds) investment assets 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 Net Asset Value as a Practical Expedient Total As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 3 $ 69 $ — $ — $ 72 International equity (*) — 22 — — 22 Fixed income: Pooled funds — 24 — — 24 Cash equivalents and other 2 — — 1 3 Total $ 5 $ 115 $ — $ 1 $ 121 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient Total As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 2,405 $ 1,159 $ — $ — $ 3,564 26 % 31 % International equity (*) 1,555 1,403 — — 2,958 25 25 Fixed income: 23 24 U.S. Treasury, government, and agency bonds — 841 — — 841 Mortgage- and asset-backed securities — 8 — — 8 Corporate bonds — 1,201 — — 1,201 Pooled funds — 650 — — 650 Cash equivalents and other 217 11 — — 228 Real estate investments 469 — — 1,188 1,657 14 13 Special situations — — — 180 180 3 1 Private equity — — — 669 669 9 6 Total $ 4,646 $ 5,273 $ — $ 2,037 $ 11,956 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 2,010 $ 927 $ — $ — $ 2,937 26 % 29 % International equity (*) 1,231 1,110 — — 2,341 25 22 Fixed income: 23 29 U.S. Treasury, government, and agency bonds — 588 — — 588 Mortgage- and asset-backed securities — 13 — — 13 Corporate bonds — 991 — — 991 Pooled funds — 524 — — 524 Cash equivalents and other 996 2 — — 998 Real estate investments 310 — — 1,152 1,462 14 13 Special situations — — 180 180 3 2 Private equity — — — 549 549 9 5 Total $ 4,547 $ 4,155 $ — $ 1,881 $ 10,583 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2017 and 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets 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 Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 155 $ 323 $ — $ — $ 478 International equity (*) — 166 — — 166 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 39 — — 39 Cash equivalents and other 84 25 — 48 157 Real estate investments 3 — — 16 19 Private equity — — — 1 1 Total $ 242 $ 638 $ — $ 65 $ 945 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2017 and 2016 , special situations (absolute return and hedge funds) investment assets are presented in the table 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 Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 155 $ 323 $ — $ — $ 478 International equity (*) — 166 — — 166 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 39 — — 39 Cash equivalents and other 84 25 — 48 157 Real estate investments 3 — — 16 19 Private equity — — — 1 1 Total $ 242 $ 638 $ — $ 65 $ 945 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2017 and 2016 , special situations (absolute return and hedge funds) investment assets are presented in the table 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 Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 69 $ — $ — $ 72 International equity (*) — 22 — — 22 Fixed income: Pooled funds — 24 — — 24 Cash equivalents and other 2 — — 1 3 Total $ 5 $ 115 $ — $ 1 $ 121 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
SOUTHERN Co GAS | Pension plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 217 $ 267 Other deferred charges and assets 85 58 Other current liabilities (3 ) (2 ) Employee benefit obligations (198 ) (206 ) |
Estimated pension benefit payments | At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 100 2019 77 2020 79 2021 79 2022 80 2023 to 2027 392 |
SOUTHERN Co GAS | Other postretirement benefit plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following: 2017 2016 (in millions) Other regulatory assets, deferred $ 46 $ 52 Employee benefit obligations (185 ) (203 ) |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost for all periods presented were as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) Service cost $ 2 $ 1 $ 1 $ 2 Interest cost 10 5 5 13 Expected return on plan assets (7 ) (3 ) (3 ) (7 ) Amortization of regulatory assets — 2 — — Amortization: Prior service costs (3 ) — (1 ) (3 ) Net (gain)/loss 4 — 2 6 Net periodic postretirement benefit cost $ 6 $ 5 $ 4 $ 11 |
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. At December 31, 2017 , estimated benefit payments were as follows: Benefit Payments (in millions) 2018 $ 20 2019 20 2020 21 2021 21 2022 22 2023 to 2027 105 |
Contingencies and Regulatory 33
Contingencies and Regulatory Matters (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Loss Contingencies [Line Items] | |
Schedule of revised cost and schedule | Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows: (in billions) Project capital cost forecast $ 7.3 Net investment as of December 31, 2017 (3.4 ) Remaining estimate to complete $ 3.9 Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds. |
GEORGIA POWER CO | |
Loss Contingencies [Line Items] | |
Schedule of revised cost and schedule | The Company's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows: (in billions) Project capital cost forecast $ 7.3 Net investment as of December 31, 2017 (3.4 ) Remaining estimate to complete $ 3.9 Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds. |
SOUTHERN Co GAS | |
Loss Contingencies [Line Items] | |
Schedule of unrecognized ratemaking amounts | The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025. December 31, 2017 December 31, 2016 (in millions) Atlanta Gas Light $ 104 $ 110 Virginia Natural Gas 11 11 Elizabethtown Gas (*) 8 6 Nicor Gas 2 2 Total $ 125 $ 129 (*) See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the pending asset sale. |
Joint Ownership Agreements (Tab
Joint Ownership Agreements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2017 , Alabama Power's, Georgia Power's, Southern Power's, and Southern Company Gas' 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 Ownership Plant in Service Accumulated Depreciation CWIP (in millions) Plant Vogtle (nuclear) Units 1 and 2 45.7 % $ 3,564 $ 2,141 $ 70 Plant Hatch (nuclear) 50.1 1,321 595 87 Plant Miller (coal) Units 1 and 2 91.8 1,717 619 54 Plant Scherer (coal) Units 1 and 2 8.4 261 93 8 Plant Wansley (coal) 53.5 1,053 335 72 Rocky Mountain (pumped storage) 25.4 182 132 — Plant Stanton (combined cycle) Unit A 65.0 155 55 — Dalton Pipeline (natural gas pipeline) 50.0 241 2 13 |
Temporary Equity | The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) Balance at December 31, 2014 $ 375 Issued — Redeemed (262 ) Issuance costs 5 Balance at December 31, 2015: 118 Issued — Redeemed — Balance at December 31, 2016: 118 Issued 250 Redeemed (38 ) Issuance costs (6 ) Balance at December 31, 2017: $ 324 |
ALABAMA POWER CO | |
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 an associated gas pipeline, the Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2017 were as follows: Facility Total MW Capacity Company Ownership Plant in Service Accumulated Depreciation Construction Work in Progress (in millions) Greene County 500 60.00 % (1) $ 172 $ 65 $ 2 Plant Miller Units 1 and 2 1,320 91.84 % (2) 1,717 619 54 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth Energy Cooperative, Inc. |
GEORGIA POWER CO | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2017 , 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 45.7 % $ 3,564 $ 2,141 $ 70 Plant Hatch (nuclear) 50.1 1,321 595 87 Plant Wansley (coal) 53.5 1,053 335 72 Plant Scherer (coal) Units 1 and 2 8.4 261 93 8 Unit 3 75.0 1,232 468 26 Rocky Mountain (pumped storage) 25.4 182 132 — |
GULF POWER CO | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2017 , the Company's percentage ownership and investment in these jointly-owned facilities were as follows: Plant Scherer Unit 3 (coal) Plant Daniel Units 1 & 2 (coal) (in millions) Plant in service $ 374 $ 696 Accumulated depreciation 147 225 Construction work in progress 9 4 Company ownership 25 % 50 % |
MISSISSIPPI POWER CO | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2017 , the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows: Generating Plant Company Ownership Plant in Service Accumulated Depreciation CWIP (in millions) Greene County Units 1 and 2 40 % $ 164 $ 55 $ 1 Daniel Units 1 and 2 50 % $ 713 $ 189 $ 4 |
SOUTHERN Co GAS | |
Jointly Owned Utility Plant Interests [Line Items] | |
Temporary Equity | The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below: Predecessor – (in millions) Balance at December 31, 2015 $ — Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest 46 Net income attributable to noncontrolling interest 14 Distribution to noncontrolling interest (19 ) Balance at June 30, 2016 $ 41 Successor – (in millions) Balance at July 1, 2016 $ 174 Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable (174 ) Balance at December 31, 2016 $ — |
Equity Method Investments | The carrying amounts of the Company's equity method investments as of December 31, 2017 and 2016 and related income from those investments for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were as follows: Balance Sheet Information December 31, 2017 December 31, 2016 (in millions) SNG (*) $ 1,262 $ 1,394 Triton 42 44 Horizon Pipeline 30 30 PennEast Pipeline 57 22 Atlantic Coast Pipeline 41 33 Pivotal JAX LNG, LLC 44 16 Other 1 2 Total $ 1,477 $ 1,541 (*) Includes a $104 million decrease at December 31, 2017 related to the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. Successor Predecessor Income Statement Information Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) SNG $ 88 $ 56 $ — $ — Triton 4 2 1 4 Horizon Pipeline 2 1 1 2 Atlantic Coast Pipeline 6 1 — — PennEast Pipeline 6 — — — Total $ 106 $ 60 $ 2 $ 6 Selected financial information of SNG as of December 31, 2017 and 2016 and for the year ended December 31, 2017 and for the period September 1, 2016 through December 31, 2016 is as follows: As of December 31, Balance Sheet Information 2017 2016 (in millions) Current assets $ 82 $ 95 Property, plant, and equipment 2,439 2,451 Deferred charges and other assets 121 129 Total Assets $ 2,642 $ 2,675 Current liabilities $ 110 $ 588 Long-term debt 1,102 706 Other deferred charges and other liabilities 76 22 Total Liabilities $ 1,288 $ 1,316 Total Stockholders' Equity 1,354 1,359 Total Liabilities and Stockholders' Equity $ 2,642 $ 2,675 Income Statement Information Year ended December 31, 2017 September 1, 2016 (in millions) Revenues $ 544 $ 230 Operating income 246 138 Net income $ 175 $ 115 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current $ (62 ) $ 1,184 $ (177 ) Deferred (6 ) (342 ) 1,266 (68 ) 842 1,089 State — Current 37 (108 ) (33 ) Deferred 173 217 138 210 109 105 Total $ 142 $ 951 $ 1,194 |
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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 10,267 $ 15,392 Property basis differences 955 2,708 Leveraged lease basis differences 251 314 Employee benefit obligations 516 737 Premium on reacquired debt 54 89 Regulatory assets associated with employee benefit obligations 1,046 1,584 Regulatory assets associated with AROs 1,225 1,781 Other 697 907 Total 15,011 23,512 Deferred tax assets — Federal effect of state deferred taxes 326 597 Employee benefit obligations 1,307 1,868 Over recovered fuel clause — 66 Other property basis differences 446 401 Deferred costs 69 100 ITC carryforward 2,420 1,974 Federal NOL carryforward 518 1,084 Unbilled revenue 57 92 Other comprehensive losses 84 152 AROs 1,197 1,732 Estimated Loss on Kemper IGCC 722 484 Deferred state tax assets 328 266 Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) 465 — Other 485 679 Total 8,424 9,495 Valuation allowance (149 ) (23 ) Total deferred income taxes 6,736 14,040 Portion included in accumulated deferred tax assets (106 ) (52 ) Accumulated deferred income taxes $ 6,842 $ 14,092 |
Summary of operating loss carryforward | At December 31, 2017 , the state NOL carryforwards for Southern Company's subsidiaries were as follows: Jurisdiction Approximate NOL Carryforwards Approximate Net State Income Tax Benefit Tax Year NOL Begins Expiring (in millions) Mississippi $ 2,890 $ 114 2032 Oklahoma 986 47 2036 Georgia 524 23 2019 New York 229 13 2036 New York City 209 15 2036 Florida 304 13 2034 Other states 465 24 Various Total $ 5,607 $ 249 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 12.5 2.1 1.9 Employee stock plans dividend deduction (4.1 ) (1.2 ) (1.2 ) Non-deductible book depreciation 3.1 0.9 1.2 AFUDC-Equity (2.6 ) (2.0 ) (2.2 ) Non-deductible equity portion on Kemper IGCC write-off 15.7 — — ITC basis difference (1.7 ) (5.0 ) (1.5 ) Federal PTCs (12.1 ) (1.2 ) — Amortization of ITC (4.2 ) (0.9 ) (0.5 ) Tax Reform Legislation (25.6 ) — — Other (2.7 ) (0.4 ) 0.2 Effective income tax rate 13.3 % 27.3 % 32.9 % |
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: 2017 2016 2015 (in millions) Unrecognized tax benefits at beginning of year $ 484 $ 433 $ 170 Tax positions increase from current periods 10 45 43 Tax positions increase from prior periods 10 21 240 Tax positions decrease from prior periods (196 ) (15 ) (20 ) Reductions due to settlements (290 ) — — Balance at end of year $ 18 $ 484 $ 433 |
Impact on effective tax rate | The impact on Southern Company's effective tax rate, if recognized, is as follows: 2017 2016 2015 (in millions) Tax positions impacting the effective tax rate $ 18 $ 20 $ 10 Tax positions not impacting the effective tax rate — 464 423 Balance of unrecognized tax benefits $ 18 $ 484 $ 433 |
ALABAMA POWER CO | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current $ 136 $ 103 $ 110 Deferred 336 339 320 472 442 430 State — Current 23 20 8 Deferred 73 69 68 96 89 76 Total $ 568 $ 531 $ 506 |
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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 2,336 $ 4,307 Property basis differences 398 456 Premium on reacquired debt 16 26 Employee benefit obligations 162 201 Regulatory assets associated with employee benefit obligations 260 393 Asset retirement obligations 220 289 Regulatory assets associated with asset retirement obligations 249 347 Other 147 179 Total 3,788 6,198 Deferred tax assets — Federal effect of state deferred taxes 143 266 Unbilled fuel revenue 22 36 Storm reserve 5 21 Employee benefit obligations 286 427 Other comprehensive losses 10 19 Asset retirement obligations 469 636 Other 93 139 Total 1,028 1,544 Accumulated deferred income taxes, net $ 2,760 $ 4,654 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.4 4.2 3.8 Non-deductible book depreciation 0.9 1.0 1.2 AFUDC equity (1.0) (0.7) (1.6) Tax Reform Legislation 0.3 — — Other — (0.7) — Effective income tax rate 39.6% 38.8% 38.4% |
GEORGIA POWER CO | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal – Current $ 256 $ 391 $ 515 Deferred 504 319 176 760 710 691 State – Current 116 6 81 Deferred (46 ) 64 (3 ) 70 70 78 Total $ 830 $ 780 $ 769 |
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: 2017 2016 (in millions) Deferred tax liabilities – Accelerated depreciation $ 3,540 $ 5,266 Property basis differences — 957 Employee benefit obligations 287 428 Premium on reacquired debt 34 56 Regulatory assets – Storm damage reserves 89 83 Employee benefit obligations 348 546 Asset retirement obligations 501 726 Retired assets 30 55 Asset retirement obligations 132 182 Other 100 83 Total 5,061 8,382 Deferred tax assets – Federal effect of state deferred taxes 72 173 Employee benefit obligations 423 661 Property basis differences 92 105 Other deferred costs 69 100 State investment tax credit carryforward 318 201 Federal tax credit carryforward 97 84 Unbilled fuel revenue 26 47 Regulatory liabilities associated with asset retirement obligations 5 33 Asset retirement obligations 631 908 Regulatory liability associated with Tax Reform Legislation (not subject to normalization) 123 — Other 30 70 Total 1,886 2,382 Accumulated deferred income taxes $ 3,175 $ 6,000 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 2.0 2.1 2.5 Non-deductible book depreciation 0.7 0.8 1.2 AFUDC equity (0.6 ) (0.8 ) (0.7 ) Tax Reform Legislation (0.4 ) — — Other — (0.4 ) (0.4 ) Effective income tax rate 36.7 % 36.7 % 37.6 % |
GULF POWER CO | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal - Current $ 19 $ 34 $ (3 ) Deferred 58 45 80 77 79 77 State - Current (1 ) — 5 Deferred 14 12 10 13 12 15 Total $ 90 $ 91 $ 92 |
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: 2017 2016 (in millions) Deferred tax liabilities- Accelerated depreciation $ 552 $ 834 Property basis differences 105 123 Pension and other employee benefits 38 58 Regulatory assets 22 45 Regulatory assets associated with employee benefit obligations 44 65 Regulatory assets associated with asset retirement obligations 38 55 Other 13 12 Total 812 1,192 Deferred tax assets- Federal effect of state deferred taxes 25 37 Postretirement benefits 17 26 Pension and other employee benefits 49 72 Property differences 98 1 Regulatory liability associated with Tax Reform Legislation (not subject to normalization) 19 — Property reserve 10 17 Asset retirement obligations 38 55 Alternative minimum tax carryforward 7 18 Other 12 18 Total 275 244 Accumulated deferred income taxes $ 537 $ 948 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.7 3.4 3.9 Non-deductible book depreciation 0.2 0.6 0.5 Differences in prior years' deferred and current tax rates — (0.1) (0.1) AFUDC equity — — (1.8) Other, net 0.5 0.6 (0.6) Effective income tax rate 39.4% 39.5% 36.9% |
MISSISSIPPI POWER CO | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current $ 194 $ (31 ) $ (768 ) Deferred (753 ) (60 ) 704 (559 ) (91 ) (64 ) State — Current — (6 ) (81 ) Deferred 27 (7 ) 73 27 (13 ) (8 ) Total $ (532 ) $ (104 ) $ (72 ) |
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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 373 $ 386 Property basis difference 242 852 Regulatory assets associated with AROs 34 72 Pensions and other benefits 28 49 Regulatory assets associated with employee benefit obligations 45 70 Regulatory assets associated with the Kemper County energy facility 31 82 Regulatory assets associated with Plant Daniel 9 13 Rate differential — 141 Federal effect of state deferred taxes 9 — Ad valorem over/under recovery 11 14 Regulatory assets for Mercury and Air Toxics Standards compliance 11 8 Other 11 91 Total 804 1,778 Deferred tax assets — Fuel clause over recovered — 26 Estimated loss on Kemper IGCC 722 484 Pension and other benefits 62 96 Federal NOL 40 109 Property insurance 15 27 Premium on long-term debt 7 14 AROs 34 72 Property basis difference 70 — Affirmative adjustments 31 — Regulatory liability associated with Tax Reform Legislation (not subject to normalization) 27 — Deferred state tax assets 133 113 Deferred federal tax assets — 31 Federal effect of state deferred taxes — 19 Other 32 31 Total 1,173 1,022 Valuation allowance (net of $35 million in federal benefit) 122 — Accumulated deferred income tax (assets)/liabilities (247 ) 756 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate (35.0 )% (35.0 )% (35.0 )% State income tax, net of federal deduction 0.6 (5.7 ) (6.3 ) Non-deductible book depreciation 0.1 0.7 1.3 AFUDC-equity — (28.5 ) (49.6 ) Non-deductible equity portion on Kemper IGCC write-off 5.3 — — Tax Reform Legislation 11.9 — — Other — — (2.9 ) Effective income tax rate (benefit rate) (17.1 )% (68.5 )% (92.5 )% |
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: 2017 2016 2015 (in millions) Unrecognized tax benefits at beginning of year $ 465 $ 421 $ 165 Tax positions increase from current periods — 26 32 Tax positions increase from prior periods 2 18 224 Tax positions decrease from prior periods (177 ) — — Reductions due to settlements (290 ) — — Balance at end of year $ — $ 465 $ 421 |
Impact on effective tax rate | The impact on the Company's effective tax rate, if recognized, is as follows: 2017 2016 2015 (in millions) Tax positions impacting the effective tax rate $ — $ 1 $ (2 ) Tax positions not impacting the effective tax rate — 464 423 Balance of unrecognized tax benefits $ — $ 465 $ 421 |
Accrued interest for unrecognized tax benefits | Accrued interest for unrecognized tax benefits was as follows: 2017 2016 2015 (in millions) Interest accrued at beginning of year $ 28 $ 13 $ 3 Interest accrued during the year (28 ) 15 10 Balance at end of year $ — $ 28 $ 13 |
SOUTHERN POWER CO | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2017 2016 2015 (in millions) Federal — Current (*) $ (566 ) $ 928 $ 12 Deferred (*) (312 ) (1,098 ) 10 (878 ) (170 ) 22 State — Current (110 ) (60 ) (32 ) Deferred 49 35 31 (61 ) (25 ) (1 ) Total $ (939 ) $ (195 ) $ 21 (*) ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $316 million for 2017 , $1.13 billion for 2016 , and $246 million for 2015. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits. |
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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation and other property basis differences $ 1,922 $ 2,440 Levelized capacity revenues 26 28 Other 6 27 Total deferred income tax liabilities 1,954 2,495 Deferred tax assets — Federal effect of state deferred taxes 42 53 Basis difference on ITCs 184 292 Alternative minimum tax carryforward 21 15 Unrealized tax credits 2,002 1,685 Federal net operating loss (NOL) 333 808 Deferred state tax assets 77 60 Other partnership basis differences 24 16 Other 10 8 Total deferred income tax assets 2,693 2,937 Valuation Allowance (13 ) — Net deferred income tax assets 2,680 2,937 Total deferred income tax asset (liability) $ 726 $ 442 Recognized in the consolidated balance sheets: Accumulated deferred income taxes – assets $ 925 $ 594 Accumulated deferred income taxes – liability $ (199 ) $ (152 ) |
Summary of operating loss carryforward | The state NOL carryforwards by state jurisdiction were as follows: Jurisdiction Approximate NOL Carryforwards Approximate Net State Income Tax Benefit Tax Year NOL Expires (in millions) Oklahoma $ 978 $ 46 2035 Florida 283 12 2033 South Carolina 48 2 2035 Other states 23 1 2029-2035 Balance at year end $ 1,332 $ 61 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction (22.2 ) (9.1 ) (0.3 ) Amortization of ITC (31.8 ) (20.6 ) (5.0 ) ITC basis difference (10.0 ) (89.0 ) (21.5 ) Production tax credits (72.5 ) (23.3 ) (0.6 ) Tax Reform Legislation (416.1 ) — — Noncontrolling interests (8.6 ) (6.2 ) (1.7 ) Other 0.5 4.6 2.5 Effective income tax rate (benefit) (525.7 )% (108.6 )% 8.4 % |
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: 2017 2016 2015 (in millions) Balance at beginning of year $ 17 $ 8 $ 5 Tax positions increase from current periods — 17 9 Tax positions decrease from prior periods (17 ) (8 ) (6 ) Balance at end of year $ — $ 17 $ 8 |
SOUTHERN Co GAS | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year ended December 31, 2015 (in millions) (in millions) Federal — Current $ 103 $ — $ 67 $ (13 ) Deferred 170 65 8 198 273 65 75 185 State — Current 27 (16 ) 12 10 Deferred 67 27 — 18 94 11 12 28 Total $ 367 $ 76 $ 87 $ 213 |
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: 2017 2016 (in millions) Deferred tax liabilities — Accelerated depreciation $ 1,436 $ 1,954 Property basis differences 204 311 Regulatory assets associated with employee benefit obligations 79 125 Other 208 164 Total 1,927 2,554 Deferred tax assets — Federal net operating loss 92 59 Federal effect of state deferred taxes 54 42 Employee benefit obligations 185 165 Regulatory liability associated with the Tax Reform Legislation (not subject to 295 — Other 223 332 Total 849 598 Less valuation allowances (11 ) (19 ) Total, net of valuation allowances 838 579 Accumulated deferred income taxes, net $ 1,089 $ 1,975 |
Schedule of effective income tax reconciliation | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Successor Predecessor Year ended December 31, 2017 July 1, 2016 through December 31, January 1, 2016 through June 30, 2016 Year ended December 31, 2015 Federal statutory rate 35.0% 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.0 4.0 3.5 3.4 Tax Reform Legislation 15.0 — — — State tax legislation and rate changes 6.2 — — — Other — 1.0 (0.9) (2.0) Effective income tax rate 60.2% 40.0% 37.6% 36.4% |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Estimated total obligations under these commitments at December 31, 2017 were as follows: Operating Leases Other (in millions) 2018 $ 247 $ 7 2019 250 6 2020 247 4 2021 249 5 2022 252 4 2023 and thereafter 806 38 Total $ 2,051 $ 64 |
Expected future contractual obligations | Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2018 $ 813 2019 552 2020 416 2021 375 2022 339 2023 and thereafter 2,294 Total $ 4,789 |
Estimated minimum lease payments under operating leases | As of December 31, 2017 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Barges & Railcars Other (*) Total (in millions) 2018 $ 21 $ 128 $ 149 2019 11 113 124 2020 9 99 108 2021 8 87 95 2022 6 77 83 2023 and thereafter 5 963 968 Total $ 60 $ 1,467 $ 1,527 |
ALABAMA POWER CO | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Total estimated minimum long-term obligations at December 31, 2017 were as follows: Operating Lease PPAs (in millions) 2018 $ 41 2019 43 2020 44 2021 46 2022 47 2023 and thereafter — Total commitments $ 221 |
Estimated minimum lease payments under operating leases | As of December 31, 2017 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments (a) Affiliate Operating Leases (b) Railcars Vehicles & Other Total (in millions) 2018 $ 8 $ 7 $ 6 $ 21 2019 10 7 5 22 2020 8 7 3 18 2021 7 6 1 14 2022 5 5 — 10 2023 and thereafter 16 4 — 20 Total $ 54 $ 36 $ 15 $ 105 (a) Minimum lease payments have not been reduced by minimum sublease rentals of $3 million in the future. |
GEORGIA POWER CO | |
Commitments [Line Items] | |
Estimated minimum lease payments under operating leases | As of December 31, 2017 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Affiliate Operating Leases (a) Non-Affiliate Operating Leases (b) Total (in millions) 2018 $ 10 $ 14 $ 24 2019 11 11 22 2020 11 9 20 2021 9 8 17 2022 8 6 14 2023 and thereafter 33 11 44 Total $ 82 $ 59 $ 141 (a) Includes operating leases for cellular tower space. (b) Includes operating leases for cellular tower space, facilities, railcars, and other equipment. |
Estimated long-term obligations | Estimated total long-term obligations at December 31, 2017 were as follows: Affiliate Capital Leases Affiliate Operating Leases Non-Affiliate Operating Leases Vogtle Units 1 and 2 Capacity Payments Total (in millions) 2018 $ 23 $ 62 $ 127 $ 7 $ 219 2019 23 63 128 6 220 2020 23 65 124 4 216 2021 24 66 125 5 220 2022 24 67 126 4 221 2023 and thereafter 182 412 773 38 1,405 Total $ 299 $ 735 $ 1,403 $ 64 $ 2,501 Less: amounts representing executory costs (a) 45 Net minimum lease payments 254 Less: amounts representing interest (b) 120 Present value of net minimum lease payments $ 134 (a) Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) a re estimated and included in total minimum lease payments. (b) Calculated using an adjusted incremental borrowing rate to reduce the present value of the net minimum lease payments to fair value. |
GULF POWER CO | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Estimated total minimum long-term commitments at December 31, 2017 were as follows: Operating Lease PPA (in millions) 2018 $ 79 2019 79 2020 79 2021 79 2022 79 2023 and thereafter 33 Total $ 428 |
Estimated minimum lease payments under operating leases | Estimated total minimum lease payments under these operating leases at December 31, 2017 were as follows: Minimum Lease Payments Affiliate Operating Leases (a) Non-Affiliate Operating Leases (b) Total (in millions) 2018 $ 2 $ 7 $ 9 2019 1 1 2 2020 1 1 2 2021 1 — 1 2022 1 — 1 2023 and thereafter 4 1 5 Total $ 10 $ 10 $ 20 |
MISSISSIPPI POWER CO | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Estimated minimum lease payments under operating leases at December 31, 2017 were as follows: Affiliate Operating Leases (a) Non-Affiliate Operating Lease (b) Total (in millions) 2018 $ 2 $ 1 $ 3 2019 2 1 3 2020 2 1 3 2021 2 — 2 2022 2 — 2 2023 and thereafter 7 — 7 Total $ 17 $ 3 $ 20 (a) Includes operating leases with affiliates primarily related to cellular towers. (b) Primarily includes railcar and fuel handling equipment leases for Plant Daniel. |
SOUTHERN Co GAS | |
Commitments [Line Items] | |
Expected future contractual obligations | Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2018 $ 813 2019 552 2020 416 2021 375 2022 339 2023 and thereafter 2,294 Total $ 4,789 |
Estimated minimum lease payments under operating leases | As of December 31, 2017 , the Company's estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments (in millions) 2018 $ 17 2019 16 2020 16 2021 15 2022 13 2023 and thereafter 26 Total $ 103 |
Financing (Tables)
Financing (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Line Items] | |
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities of securities due within one year at December 31 was as follows: 2017 2016 (in millions) Senior notes $ 2,354 $ 1,995 Other long-term debt 1,420 485 Revenue bonds (*) 90 76 Capitalized leases 31 32 Unamortized debt issuance expense/discount (3 ) (1 ) Total $ 3,892 $ 2,587 (*) Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. |
Temporary Equity | The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) Balance at December 31, 2014 $ 375 Issued — Redeemed (262 ) Issuance costs 5 Balance at December 31, 2015: 118 Issued — Redeemed — Balance at December 31, 2016: 118 Issued 250 Redeemed (38 ) Issuance costs (6 ) Balance at December 31, 2017: $ 324 |
Credit arrangements with banks | At December 31, 2017 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year Company 2018 2019 2020 2022 Total Unused One Year Two Years Term Out No Term Out (in millions) Southern Company (a) $ — $ — $ — $ 2,000 $ 2,000 $ 1,999 $ — $ — $ — $ — Alabama Power 35 — 500 800 1,335 1,335 — — — 35 Georgia Power — — — 1,750 1,750 1,732 — — — — Gulf Power 30 25 225 — 280 280 45 — 20 10 Mississippi Power 100 — — — 100 100 — — — 100 Southern Power Company (b) — — — 750 750 728 — — — — Southern Company Gas (c) — — — 1,900 1,900 1,890 — — — — Other 30 — — — 30 30 20 — 20 10 Southern Company Consolidated $ 195 $ 25 $ 725 $ 7,200 $ 8,145 $ 8,094 $ 65 $ — $ 40 $ 155 (a) Represents the Southern Company parent entity. (b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017 . (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
Short-term borrowings | Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017: Commercial paper $ 1,832 1.8 % Short-term bank debt 607 2.3 % Total $ 2,439 1.9 % December 31, 2016: Commercial paper $ 1,909 1.1 % Short-term bank debt 123 1.7 % Total $ 2,032 1.1 % |
ALABAMA POWER CO | |
Debt Disclosure [Line Items] | |
Credit arrangements with banks | At December 31, 2017 , committed credit arrangements with banks were as follows: Expires Expires Within One Year 2018 2020 2022 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) $ 35 $ 500 $ 800 $ 1,335 $ 1,335 $ — $ 35 |
GEORGIA POWER CO | |
Debt Disclosure [Line Items] | |
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities of securities due within one year at December 31 was as follows: 2017 2016 (in millions) Senior notes $ 750 $ 450 Capital leases 11 10 Other long-term debt 100 — Unamortized debt issuance expense (1 ) — Total $ 860 $ 460 |
Short-term borrowings | Details of short-term borrowings outstanding were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017: Short-term bank debt $ 150 2.2 % December 31, 2016: Commercial paper $ 392 1.1 % |
GULF POWER CO | |
Debt Disclosure [Line Items] | |
Credit arrangements with banks | At December 31, 2017 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2018 2019 2020 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $ 30 $ 25 $ 225 $ 280 $ 280 $ 45 $ — $ 20 $ 10 |
Short-term borrowings | Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017: Commercial paper $ 45 2.0% December 31, 2016: Commercial paper $ 168 1.1% Short-term bank debt 100 1.5% Total $ 268 1.2% |
MISSISSIPPI POWER CO | |
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, 2017 and 2016 was as follows: 2017 2016 (in millions) Parent company loans $ — $ 551 Senior notes — 35 Bank term loans 900 — Revenue bonds (*) 90 40 Capitalized leases — 3 Unamortized debt issuance expense (1 ) — Outstanding at December 31 $ 989 $ 629 (*) Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. |
Credit arrangements with banks | At December 31, 2017 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2018 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $100 $100 $100 $— $— $— $100 |
SOUTHERN POWER CO | |
Debt Disclosure [Line Items] | |
Scheduled maturities and redemptions of securities due within one year | Maturities of long-term debt for the next five years are as follows: December 31, 2017 (in millions) 2018 $ 770 2019 600 2020 825 2021 300 2022 (*) 677 (*) Represents euro-denominated debt at the U.S. dollar denominated hedge settlement amount. |
Short-term borrowings | Commercial paper is included in notes payable in the consolidated balance sheets as noted below: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2017 $ 105 2.0 % December 31, 2016 $ — N/A |
SOUTHERN Co GAS | |
Debt Disclosure [Line Items] | |
Temporary Equity | The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below: Predecessor – (in millions) Balance at December 31, 2015 $ — Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest 46 Net income attributable to noncontrolling interest 14 Distribution to noncontrolling interest (19 ) Balance at June 30, 2016 $ 41 Successor – (in millions) Balance at July 1, 2016 $ 174 Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable (174 ) Balance at December 31, 2016 $ — |
Credit arrangements with banks | At December 31, 2017 , committed credit arrangements with banks were as follows: Company Expires 2022 Unused (in millions) Southern Company Gas Capital $ 1,400 $ 1,390 Nicor Gas 500 500 Total $ 1,900 $ 1,890 |
Short-term borrowings | Details of commercial paper borrowings outstanding were as follows: Short-term Debt at the End of the Period Amount Weighted Average Interest Rate (in millions) December 31, 2017: Southern Company Gas Capital $ 1,243 1.73 % Nicor Gas 275 1.83 Total $ 1,518 1.75 % December 31, 2016: Southern Company Gas Capital $ 733 1.09 % Nicor Gas 524 0.95 Total $ 1,257 1.03 % |
Redeemable Preferred Stock | ALABAMA POWER CO | |
Debt Disclosure [Line Items] | |
Temporary Equity | 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 5.00% Class A Preferred Stock $25 10,000,000 Stated Capital (*) (*) Prior to October 1, 2022: $25.50 ; on or after October 1, 2022: Stated Capital |
Redeemable Preferred Stock | MISSISSIPPI POWER CO | |
Debt Disclosure [Line Items] | |
Temporary Equity | Information for each outstanding series is in the table below: Preferred Stock Par Value/Stated Capital Per Share Shares Outstanding Redemption Price Per Share 4.40% Preferred Stock $ 100 8,867 $ 104.32 4.60% Preferred Stock $ 100 8,643 $ 107.00 4.72% Preferred Stock $ 100 16,700 $ 102.25 5.25% Preferred Stock (*) $ 100 300,000 $ 100.00 (*) There are 1,200,000 outstanding depositary shares, each representing one-fourth of a share of the 5.25% preferred stock. |
Common Stock and Stock Compen38
Common Stock and Stock Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Share-based Compensation, Stock Options, Activity | Southern Company's activity in the stock option program for 2017 is summarized below: Shares Subject to Option Weighted Average Exercise Price (in millions) Outstanding at December 31, 2016 24.6 $ 41.28 Exercised 6.0 40.03 Cancelled — 39.90 Outstanding and Exercisable at December 31, 2017 18.6 $ 41.68 |
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 2017 2016 2015 Expected volatility 15.6% 15.0% 12.9% Expected term (in years) 3 3 3 Interest rate 1.4% 0.8% 1.0% Weighted average grant-date fair value $49.08 $45.06 $46.38 |
Earnings per share | Shares used to compute diluted EPS were as follows: Average Common Stock Shares 2017 2016 2015 (in millions) As reported shares 1,000 951 910 Effect of options and performance share award units 8 7 4 Diluted shares 1,008 958 914 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 331 $ 239 $ — $ — $ 570 Interest rate derivatives — 1 — — 1 Foreign currency derivatives — 129 — — 129 Nuclear decommissioning trusts: (c) Domestic equity 690 82 — — 772 Foreign equity 62 224 — — 286 U.S. Treasury and government agency securities — 251 — — 251 Municipal bonds — 68 — — 68 Corporate bonds 21 315 — — 336 Mortgage and asset backed securities — 57 — — 57 Private equity — — — 29 29 Other 19 12 — — 31 Cash equivalents 1,455 — — — 1,455 Other investments 9 — 1 — 10 Total $ 2,587 $ 1,378 $ 1 $ 29 $ 3,995 Liabilities: Energy-related derivatives (a)(b) $ 480 $ 253 $ — $ — $ 733 Interest rate derivatives — 38 — — 38 Foreign currency derivatives — 23 — — 23 Contingent consideration — — 22 — 22 Total $ 480 $ 314 $ 22 $ — $ 816 (a) Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives exclude cash collateral of $193 million . (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under " Nuclear Decommissioning " for additional information. As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 338 $ 333 $ — $ — $ 671 Interest rate derivatives — 14 — — 14 Nuclear decommissioning trusts: (c) Domestic equity 589 73 — — 662 Foreign equity 48 168 — — 216 U.S. Treasury and government agency securities — 92 — — 92 Municipal bonds — 73 — — 73 Corporate bonds 22 310 — — 332 Mortgage and asset backed securities — 183 — — 183 Private equity — — — 20 20 Other 11 15 — — 26 Cash equivalents 1,172 — — — 1,172 Other investments 9 — 1 — 10 Total $ 2,189 $ 1,261 $ 1 $ 20 $ 3,471 Liabilities: Energy-related derivatives (a)(b) $ 345 $ 285 $ — $ — $ 630 Interest rate derivatives — 29 — — 29 Foreign currency derivatives — 58 — — 58 Contingent consideration — — 18 — 18 Total $ 345 $ 372 $ 18 $ — $ 735 (a) Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives exclude cash collateral of $62 million . (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. 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, 2017 and 2016 , the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows: Fair Unfunded Redemption Redemption (in millions) As of December 31, 2017 $ 29 $ 21 Not Applicable Not Applicable As of December 31, 2016 $ 20 $ 25 Not Applicable Not Applicable |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 48,151 $ 51,348 2016 $ 45,080 $ 46,286 |
ALABAMA POWER CO | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2017: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 4 $ — $ — $ 4 Nuclear decommissioning trusts: (*) Domestic equity 442 81 — — 523 Foreign equity 62 59 — — 121 U.S. Treasury and government agency securities — 24 — — 24 Corporate bonds 21 160 — — 181 Mortgage and asset backed securities — 18 — — 18 Private equity — — — 29 29 Other 6 — — — 6 Cash equivalents 349 — — — 349 Total $ 880 $ 346 $ — $ 29 $ 1,255 Liabilities: Energy-related derivatives $ — $ 10 $ — $ — $ 10 (*) 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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 20 $ — $ — $ 20 Nuclear decommissioning trusts: (*) Domestic equity 385 72 — — 457 Foreign equity 48 47 — — 95 U.S. Treasury and government agency securities — 21 — — 21 Corporate bonds 22 146 — — 168 Mortgage and asset backed securities — 19 — — 19 Private equity — — — 20 20 Other — 10 — — 10 Cash equivalents 262 — — — 262 Total $ 717 $ 335 $ — $ 20 $ 1,072 Liabilities: Energy-related derivatives $ — $ 9 $ — $ — $ 9 (*) 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. |
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, 2017 and 2016 , the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period (in millions) As of December 31, 2017 $ 29 $ 21 Not Applicable Not Applicable As of December 31, 2016 $ 20 $ 25 Not Applicable Not Applicable |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 7,625 $ 8,305 2016 $ 7,092 $ 7,544 |
GEORGIA POWER CO | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 6 $ — $ 6 Nuclear decommissioning trusts: (*) Domestic equity 248 1 — 249 Foreign equity — 166 — 166 U.S. Treasury and government agency securities — 227 — 227 Municipal bonds — 68 — 68 Corporate bonds — 155 — 155 Mortgage and asset backed securities — 40 — 40 Other 12 12 — 24 Cash equivalents 690 — — 690 Total $ 950 $ 675 $ — $ 1,625 Liabilities: Energy-related derivatives $ — $ 19 $ — $ 19 Interest rate derivatives — 5 — 5 Total $ — $ 24 $ — $ 24 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 44 $ — $ 44 Interest rate derivatives — 2 — 2 Nuclear decommissioning trusts: (*) Domestic equity 204 1 — 205 Foreign equity — 121 — 121 U.S. Treasury and government agency securities — 71 — 71 Municipal bonds — 73 — 73 Corporate bonds — 164 — 164 Mortgage and asset backed securities — 164 — 164 Other 11 5 — 16 Total $ 215 $ 645 $ — $ 860 Liabilities: Energy-related derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 3 — 3 Total $ — $ 11 $ — $ 11 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 11,777 $ 12,531 2016 $ 10,516 $ 11,034 |
GULF POWER CO | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 21 $ — $ — $ 21 Liabilities: Energy-related derivatives $ — $ 21 $ — $ 21 As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 5 $ — $ 5 Cash equivalents 20 — — 20 Total $ 20 $ 5 $ — $ 25 Liabilities: Energy-related derivatives $ — $ 29 $ — $ 29 |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2017 $ 1,285 $ 1,334 2016 $ 1,074 $ 1,097 |
MISSISSIPPI POWER CO | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 2 $ — $ 2 Interest rate derivatives — 1 — 1 Cash equivalents 224 — — 224 Total $ 224 $ 3 $ — $ 227 Liabilities: Energy-related derivatives $ — $ 9 $ — $ 9 As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 3 $ — $ 3 Interest rate derivatives — 3 — 3 Cash equivalents 206 — — 206 Total $ 206 $ 6 $ — $ 212 Liabilities: Energy-related derivatives $ — $ 10 $ — $ 10 |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2017 $ 2,086 $ 2,076 2016 $ 2,979 $ 2,922 |
SOUTHERN POWER CO | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2017: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 3 $ — $ 3 Foreign currency derivatives — 129 — 129 Cash equivalents 21 — — 21 Total $ 21 $ 132 $ — $ 153 Liabilities: Energy-related derivatives $ — $ 13 $ — $ 13 Foreign currency derivatives — 23 — 23 Contingent consideration — — 22 22 Total $ — $ 36 $ 22 $ 58 As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, 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, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 21 $ — $ 21 Interest rate derivatives — 1 — 1 Cash equivalents 628 — — 628 Total $ 628 $ 22 $ — $ 650 Liabilities: Energy-related derivatives $ — $ 5 $ — $ 5 Foreign currency derivatives — 58 — 58 Contingent consideration — — 18 18 Total $ — $ 63 $ 18 $ 81 |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 5,841 $ 6,079 2016 $ 5,628 $ 5,691 |
SOUTHERN Co GAS | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2017 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using As of December 31, 2017: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 331 $ 223 $ — $ — $ 554 Liabilities: Energy-related derivatives (a)(b) $ 479 $ 181 $ — $ — $ 660 (a) Energy-related derivatives excludes $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $193 million . As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using As of December 31, 2016: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 338 $ 239 $ — $ — $ 577 Liabilities: Energy-related derivatives (a)(b) $ 345 $ 224 $ — $ — $ 569 (a) Energy-related derivatives excludes $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $62 million . |
Financial instruments not having carrying amount equal to fair value | The following table presents the carrying amount and fair value of the Company's long-term debt as of December 31: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: 2017 $ 6,048 $ 6,471 2016 $ 5,281 $ 5,491 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2017 , the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 900 1-month LIBOR 0.79% March 2018 $ 1 Fair Value Hedges of Existing Debt 250 5.40% 3-month LIBOR + 4.02% June 2018 — 500 1.95% 3-month LIBOR + 0.76% December 2018 (3 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 (1 ) 300 2.75% 3-month LIBOR + 0.92% June 2020 (2 ) 1,500 2.35% 1-month LIBOR + 0.87% July 2021 (31 ) Total $ 3,650 $ (36 ) |
Schedule of foreign exchange contracts | At December 31, 2017 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ 55 564 3.78% 500 1.85% June 2026 51 Total $ 1,241 € 1,100 $ 106 |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 10 $ 43 $ 73 $ 27 Other deferred charges and assets/Other deferred credits and liabilities 7 24 25 33 Total derivatives designated as hedging instruments for regulatory purposes $ 17 $ 67 $ 98 $ 60 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Other current liabilities $ 3 $ 14 $ 23 $ 7 Interest rate derivatives: Other current assets/Other current liabilities 1 4 12 1 Other deferred charges and assets/Other deferred credits and liabilities — 34 1 28 Foreign currency derivatives: Other current assets/Other current liabilities — 23 — 25 Other deferred charges and assets/Other deferred credits and liabilities 129 — — 33 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 133 $ 75 $ 36 $ 94 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Other current liabilities $ 380 $ 437 $ 489 $ 483 Other deferred charges and assets/Other deferred credits and liabilities 170 215 66 81 Interest rate derivatives: Other current assets/Other current liabilities — — 1 — Total derivatives not designated as hedging instruments $ 550 $ 652 $ 556 $ 564 Gross amounts recognized $ 700 $ 794 $ 690 $ 718 Gross amounts offset (a) $ (405 ) $ (598 ) $ (462 ) $ (524 ) Net amounts recognized in the Balance Sheets (b) $ 295 $ 196 $ 228 $ 194 (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016 , respectively. (b) Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017. |
Pre-tax effects on the balance sheets | At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (34 ) $ (16 ) Other regulatory liabilities, current $ 7 $ 56 Other regulatory assets, deferred (18 ) (19 ) Other regulatory liabilities, deferred 1 12 Total energy-related derivative gains (losses) (*) $ (52 ) $ (35 ) $ 8 $ 68 (*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016 , respectively. |
Pre-tax effects on the statements of income | For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Amount Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Energy-related derivatives $ (47 ) $ 18 $ — Depreciation and amortization $ (16 ) $ 2 $ — Cost of natural gas (2 ) (1 ) — Interest rate derivatives (2 ) (180 ) (22 ) Interest expense, net of amounts capitalized (21 ) (18 ) (9 ) Foreign currency derivatives 140 (58 ) — Interest expense, net of amounts capitalized (23 ) (13 ) — Other income (expense), net (*) 160 (82 ) — Total $ 91 $ (220 ) $ (22 ) $ 98 $ (112 ) $ (9 ) (*) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record euro-denominated notes. |
Pre-tax effect of interest rate and energy related derivatives | For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows: Derivatives in Fair Value Hedging Relationships Gain (Loss) Derivative Category Statements of Income Location 2017 2016 2015 (in millions) Interest rate derivatives: Interest expense, net of amounts capitalized $ (22 ) $ (21 ) $ 2 |
Pre-tax effect of interest rate and energy related derivatives | For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Derivatives Not Designated as Hedging Instruments Unrealized Gain (Loss) Recognized in Income Amount Derivative Category Statements of Income Location 2017 2016 2015 (in millions) Energy-related derivatives Wholesale electric revenues $ (4 ) $ 2 $ (5 ) Fuel — — 3 Natural gas revenues (*) (80 ) 33 — Cost of natural gas (2 ) 3 — Total $ (86 ) $ 38 $ (2 ) (*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016 , respectively. |
ALABAMA POWER CO | |
Derivative [Line Items] | |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related derivatives was reflected on the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 2 $ 6 $ 13 $ 5 Other deferred charges and assets/Other deferred credits and liabilities 2 4 7 4 Total derivatives designated as hedging instruments for regulatory purposes $ 4 $ 10 $ 20 $ 9 Gross amounts recognized $ 4 $ 10 $ 20 $ 9 Gross amounts offset $ (4 ) $ (4 ) $ (8 ) $ (8 ) Net amounts recognized in the Balance Sheets $ — $ 6 $ 12 $ 1 |
Pre-tax effects on the balance sheets | At December 31, 2017 and 2016 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (4 ) $ (1 ) Other regulatory liabilities, current $ 1 $ 8 Other regulatory assets, deferred (3 ) — Other regulatory liabilities, deferred — 4 Total energy-related derivative gains (losses) $ (7 ) $ (1 ) $ 1 $ 12 |
Pre-tax effects on the statements of income | For the years ended December 31, 2017 , 2016 , and 2015 , 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 OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Interest rate derivatives $ — $ (3 ) $ (7 ) Interest expense, net of amounts capitalized $ (6 ) $ (6 ) $ (3 ) |
GEORGIA POWER CO | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2017 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Fair Value Hedges of Existing Debt $ 250 5.40% 3-month LIBOR + 4.02% June 2018 $ — 500 1.95% 3-month LIBOR + 0.76% December 2018 (3 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 (1 ) Total $ 950 $ (4 ) |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 2 $ (9 ) $ 30 $ 1 Other deferred charges and assets/Other deferred credits and liabilities 4 (10 ) 14 7 Total derivatives designated as hedging instruments for regulatory purposes $ 6 $ (19 ) $ 44 $ 8 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ — $ (4 ) $ 2 $ — Other deferred charges and assets/Other deferred credits and liabilities — (1 ) — 3 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ — $ (5 ) $ 2 $ 3 Gross amounts recognized $ 6 $ (24 ) $ 46 $ 11 Gross amounts offset $ (6 ) $ 6 $ (8 ) $ (8 ) Net amounts recognized in the Balance Sheets $ — $ (18 ) $ 38 $ 3 |
Pre-tax effects on the balance sheets | At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (7 ) $ — Other regulatory liabilities, current $ — $ 29 Other regulatory assets, deferred (6 ) — Other deferred credits and liabilities — 7 Total energy-related derivative gains (losses) $ (13 ) $ — $ — $ 36 |
Pre-tax effects on the statements of income | For the years ended December 31, 2017 , 2016 , and 2015 , 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 Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Interest rate derivatives $ 1 $ — $ (15 ) Interest expense, net of amounts capitalized $ (4 ) $ (4 ) $ (3 ) |
GULF POWER CO | |
Derivative [Line Items] | |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related derivatives was reflected on the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ — $ 14 $ 4 $ 12 Other deferred charges and assets/Other deferred credits and liabilities — 7 1 17 Total derivatives designated as hedging instruments for regulatory purposes $ — $ 21 $ 5 $ 29 Gross amounts recognized $ — $ 21 $ 5 $ 29 Gross amounts offset $ — $ — $ (4 ) $ (4 ) Net amounts recognized on the Balance Sheets $ — $ 21 $ 1 $ 25 |
Pre-tax effects on the balance sheets | At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (14 ) $ (9 ) Other regulatory liabilities, current $ — $ 1 Other regulatory assets, deferred (7 ) (16 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (21 ) $ (25 ) $ — $ 1 (*) The unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheets. |
MISSISSIPPI POWER CO | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2017 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 900 1-month LIBOR 0.79% March 2018 $ 1 |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related derivatives and interest rate derivatives was reflected on the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 1 $ 6 $ 2 $ 6 Other deferred charges and assets/Other deferred credits and liabilities 1 3 2 5 Total derivatives designated as hedging instruments for regulatory purposes $ 2 $ 9 $ 4 $ 11 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ 1 $ — $ 2 $ — Other deferred charges and assets/Other deferred credits and liabilities — — 1 — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 1 $ — $ 3 $ — Gross amounts recognized $ 3 $ 9 $ 7 $ 11 Gross amounts offset $ (2 ) $ (2 ) $ (3 ) $ (3 ) Net amounts recognized in the Balance Sheets $ 1 $ 7 $ 4 $ 8 |
Pre-tax effects on the balance sheets | At December 31, 2017 and 2016 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (5 ) $ (5 ) Other current liabilities $ — $ 1 Other regulatory assets, deferred (2 ) (3 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (7 ) $ (8 ) $ — $ 1 |
SOUTHERN POWER CO | |
Derivative [Line Items] | |
Schedule of foreign exchange contracts | At December 31, 2017 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ 55 564 3.78% 500 1.85% June 2026 51 Total $ 1,241 € 1,100 $ 106 |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related, interest rate, and foreign currency derivatives reflected in the consolidated balance sheets is as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Other current liabilities $ 3 $ 11 $ 18 $ 4 Foreign currency derivatives: Other current assets/Other current liabilities — 23 — 25 Other deferred charges and assets/Other deferred credits and liabilities 129 — — 33 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 132 $ 34 $ 18 $ 62 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Other current liabilities $ — $ 2 $ 3 $ 1 Interest rate derivatives: Other current assets/Other current liabilities — — 1 — Total derivatives not designated as hedging instruments $ — $ 2 $ 4 $ 1 Gross amounts of recognized assets and liabilities $ 132 $ 36 $ 22 $ 63 Gross amounts offset $ (3 ) $ (3 ) $ (5 ) $ (5 ) Net amounts of assets and liabilities $ 129 $ 33 $ 17 $ 58 |
Pre-tax effects on the statements of income | For the years ended December 31, 2017 , 2016 , and 2015 , the pre-tax effects of energy-related, interest rate, and foreign currency derivatives designated as cash flow hedging instruments on the consolidated statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivative Category 2017 2016 2015 Statements of Income Location 2017 2016 2015 (in millions) (in millions) Energy-related derivatives $ (38 ) $ 14 $ — Amortization $ (17 ) $ 2 $ — Interest rate derivatives — — — Interest expense, net of amounts capitalized — (1 ) (1 ) Foreign currency derivatives 140 (58 ) — Interest expense, net of amounts capitalized (23 ) (13 ) — Other income (expense), net 159 (82 ) — Total $ 102 $ (44 ) $ — $ 119 $ (94 ) $ (1 ) |
SOUTHERN Co GAS | |
Derivative [Line Items] | |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2017 and 2016 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2017 2016 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Assets from risk management activities/Liabilities from risk management activities-current $ 5 $ 8 $ 24 $ 3 Other deferred charges and assets/Other deferred credits and liabilities — — 1 — Total derivatives designated as hedging instruments for regulatory purposes $ 5 $ 8 $ 25 $ 3 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities/Liabilities from risk management activities-current $ — $ 3 $ 4 $ 3 Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities/Liabilities from risk management activities-current $ 379 $ 434 $ 486 $ 482 Other deferred charges and assets/Other deferred credits and liabilities 170 215 66 81 Total derivatives not designated as hedging instruments $ 549 $ 649 $ 552 $ 563 Gross amounts recognized $ 554 $ 660 $ 581 $ 569 Gross amounts offset (a) $ (390 ) $ (583 ) $ (435 ) $ (497 ) Net amounts recognized in the Balance Sheets (b) $ 164 $ 77 $ 146 $ 72 (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016 , respectively. (b) Net amount of derivative instruments outstanding excludes premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017 . |
Pre-tax effects on the balance sheets | At December 31, 2017 and 2016 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2017 2016 Balance Sheet Location 2017 2016 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (4 ) $ (1 ) Other regulatory liabilities, current $ 7 $ 17 Other regulatory assets, deferred — — Other regulatory liabilities, deferred — 1 Total energy-related derivative gains (losses) (*) $ (4 ) $ (1 ) $ 7 $ 18 (*) Fair value gains and losses included in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million as of December 31, 2017 and $8 million as of December 31, 2016 . |
Pre-tax effects on the statements of income | For all periods presented, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were as follows: Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Successor Successor Derivatives in Cash Flow Hedging Relationships 2017 Statements of Income Location 2017 (in millions) (in millions) Energy-related derivatives $ (9 ) Cost of natural gas $ (2 ) Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Successor Predecessor Successor Predecessor Derivatives in Cash Flow Hedging Relationships July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Statements of Income Location July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) (in millions) (in millions) Energy-related derivatives $ 2 $ — Cost of natural gas $ (1 ) $ (1 ) Interest rate derivatives (5 ) (64 ) Interest expense, net of amounts capitalized — — Total derivatives in cash flow hedging relationships $ (3 ) $ (64 ) $ (1 ) $ (1 ) Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Predecessor Predecessor Derivatives in Cash Flow Hedging Relationships 2015 Statements of Income Location 2015 (in millions) (in millions) Energy-related derivatives $ 3 Cost of natural gas $ (10 ) Other operations and maintenance (1 ) Interest rate derivatives — Interest expense, net of amounts capitalized 2 Total derivatives in cash flow hedging relationships $ 3 $ (9 ) |
Pre-tax effect of interest rate and energy related derivatives | For all periods presented, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Gain (Loss) Successor Predecessor Derivatives in Non-Designated Hedging Relationships Statements of Income Location Year Ended December 31, 2017 July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Year Ended December 31, 2015 (in millions) (in millions) Energy-related derivatives Natural gas revenues (*) $ (80 ) $ 33 $ (1 ) $ 56 Cost of natural gas (2 ) 3 (62 ) (6 ) Total derivatives in non-designated hedging relationships $ (82 ) $ 36 $ (63 ) $ 50 (*) Excludes the impact of weather derivatives recorded in natural gas revenues of $23 million for the successor year ended December 31, 2017 , $6 million for the successor period of July 1, 2016 through December 31, 2016 , $3 million for the predecessor period of January 1, 2016 through June 30, 2016 , and $12 million for the predecessor year ended December 31, 2015 . |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition | The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows: 2017 (in millions) Restricted cash $ 16 CWIP 534 Other assets 5 Accounts payable (16 ) Total purchase price $ 539 The following table presents the final purchase price allocation: Southern Company Gas Purchase Price (in millions) Current assets $ 1,557 Property, plant, and equipment 10,108 Goodwill 5,967 Intangible assets 400 Regulatory assets 1,118 Other assets 229 Current liabilities (2,201 ) Other liabilities (4,742 ) Long-term debt (4,261 ) Noncontrolling interest (174 ) Total purchase price $ 8,001 The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017 . Project Facility Resource Seller; Acquisition Date Approximate Nameplate Capacity (MW) Location Southern Power Percentage Ownership Actual/Expected COD PPA Contract Period Business Acquisitions During the Year Ended December 31, 2017 Bethel Wind Invenergy Wind Global LLC, January 6, 2017 276 Castro County, TX 100 % January 2017 12 years Cactus Flats (a) Wind RES America Developments, Inc. 148 Concho County, TX 100 % Third quarter 2018 12 years and 15 years Business Acquisitions Subsequent to December 31, 2017 Gaskell West 1 Solar Recurrent Energy Development Holdings, LLC, January 26, 2018 20 Kern County, CA 100% of Class B (b) March 20 years (a) On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. (b) Southern Power owns 100% of the class B membership interest under a tax equity partnership agreement. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: Southern Power (b) (c) $ 2,345 Noncontrolling interests (d) (e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 - and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. (b) At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. The following table presents Southern Power's acquisitions for the year ended December 31, 2016 . Project Facility Resource Seller, Acquisition Date Approximate MW ) Location Ownership Percentage Actual COD PPA Acquisitions for the Year Ended December 31, 2016 Boulder 1 Solar SunPower 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC 20 Imperial County, CA 100 % (b) February 2016 20 years East Pecos Solar First Solar, Inc. 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc. 102 Dawson County, TX 100 % April 2017 15 years Mankato (d) Natural Gas Calpine Corporation October 26, 2016 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC 74 Rutherford County, NC 100 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc. 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc. 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years (a) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) Southern Power originally purchased 90% , with a minority owner owning 10% . During 2017, Southern Power acquired the remaining 10% ownership interest. (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) Southern Power owns 90.1% , with the minority owner, Invenergy Wind Global LLC, owning 9.9% . The following table presents the final purchase price allocation: PowerSecure Purchase Price (in millions) Current assets $ 172 Property, plant, and equipment 46 Intangible assets 106 Goodwill 284 Other assets 4 Current liabilities (121 ) Long-term debt, including current portion (48 ) Deferred credits and other liabilities (14 ) Total purchase price $ 429 |
Business Acquisition, Pro Forma Information | The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger. 2016 2015 Operating revenues (in millions) $ 21,791 $ 21,430 Net income attributable to Southern Company (in millions) $ 2,591 $ 2,665 Basic EPS $ 2.70 $ 2.85 Diluted EPS $ 2.68 $ 2.84 |
SOUTHERN Co GAS | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition | The following table presents the final purchase price allocation: Successor Predecessor New Basis Old Basis Change in Basis (in millions) (in millions) Current assets $ 1,557 $ 1,474 $ 83 Property, plant, and equipment 10,108 10,148 (40 ) Goodwill 5,967 1,813 4,154 Other intangible assets 400 101 299 Regulatory assets 1,118 679 439 Other assets 229 273 (44 ) Current liabilities (2,201 ) (2,205 ) 4 Other liabilities (4,742 ) (4,600 ) (142 ) Long-term debt (4,261 ) (3,709 ) (552 ) Contingently redeemable noncontrolling interest (174 ) (41 ) (133 ) Total purchase price/equity $ 8,001 $ 3,933 $ 4,068 |
SOUTHERN POWER CO | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition | The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: The Company (b) (c) $ 2,345 Noncontrolling interests (d) (e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 - and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. (b) At December 31, 2016, $461 million is included in acquisitions payable on the consolidated balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows: 2017 (in millions) Restricted cash $ 16 CWIP 534 Other assets 5 Accounts payable (16 ) Total purchase price $ 539 The following table presents the Company's acquisitions for the year ended December 31, 2016 . Project Facility Resource Seller, Acquisition Date Approximate MW ) Location Ownership Percentage Actual COD PPA Acquisitions for the Year Ended December 31, 2016 Boulder 1 Solar SunPower Corporation, 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC, 20 Imperial County, CA 100 % (b) February 2016 20 years East Pecos Solar First Solar, Inc., 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC, 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC, 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower Corporation, 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc., 102 Dawson County, TX 100 % April 2017 15 years Mankato (d) Natural Gas Calpine Corporation, 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC, 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC, 74 Rutherford County, NC 100 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc., 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc., 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy Wind Global LLC, 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years (a) The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) The Company originally purchased 90% , with a minority owner owning 10% . During 2017, the Company acquired the remaining 10% ownership interest. See Note 10 for additional information. (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) The Company owns 90.1% , with the minority owner, Invenergy Wind Global LLC, owning 9.9% . The following table presents the Company's acquisition activity for the year ended, and subsequent to, December 31, 2017. Project Facility Resource Seller, Acquisition Date Approximate Nameplate Capacity ( MW ) Location Ownership Percentage Actual / Expected COD PPA Contract Period Business Acquisitions During the Year Ended December 31, 2017 Bethel Wind Invenergy Wind Global LLC, 276 Castro County, TX 100 % January 2017 12 years Cactus Flats (a) Wind RES America Developments, Inc., 148 Concho County, TX 100 % Third quarter 2018 12 years and 15 years Asset Acquisitions Subsequent to December 31, 2017 Gaskell West 1 Solar Recurrent Energy Development Holdings, LLC, 20 Kern County, CA 100% of Class B (b) March 20 years (a) On July 31, 2017, the Company purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, the Company expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. (b) The Company owns 100% of the class B membership interest under a tax equity partnership agreement. |
Business Acquisition, Pro Forma Information | The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows: 2017 (in millions) Restricted cash $ 16 CWIP 534 Other assets 5 Accounts payable (16 ) Total purchase price $ 539 |
Segment and Related Informati42
Segment and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | |
Financial data for business segments | Financial data for business segments and products and services for the years ended December 31, 2017 , 2016 , and 2015 was as follows: Electric Utilities Traditional Electric Operating Companies Southern Power Eliminations Total Southern Company Gas All Other Eliminations Consolidated (in millions) 2017 Operating revenues $ 16,884 $ 2,075 $ (419 ) $ 18,540 $ 3,920 $ 741 $ (170 ) $ 23,031 Depreciation and amortization 1,954 503 — 2,457 501 52 — 3,010 Interest income 14 7 — 21 3 11 (9 ) 26 Earnings from equity method investments 1 — — 1 106 (1 ) — 106 Interest expense 820 191 — 1,011 200 490 (7 ) 1,694 Income taxes 1,021 (939 ) — 82 367 (307 ) — 142 Segment net income (loss) (a)(b)(c) (193 ) 1,071 — 878 243 (279 ) — 842 Total assets 72,204 15,206 (325 ) 87,085 22,987 2,552 (1,619 ) 111,005 Gross property additions 3,836 268 — 4,104 1,525 355 — 5,984 2016 Operating revenues $ 16,803 $ 1,577 $ (439 ) $ 17,941 $ 1,652 $ 463 $ (160 ) $ 19,896 Depreciation and amortization 1,881 352 — 2,233 238 31 — 2,502 Interest income 6 7 — 13 2 20 (15 ) 20 Earnings from equity method investments 2 — — 2 60 (3 ) — 59 Interest expense 814 117 — 931 81 317 (12 ) 1,317 Income taxes 1,286 (195 ) — 1,091 76 (216 ) — 951 Segment net income (loss) (a) (b) 2,233 338 — 2,571 114 (230 ) (7 ) 2,448 Total assets 72,141 15,169 (316 ) 86,994 21,853 2,474 (1,624 ) 109,697 Gross property additions 4,852 2,114 — 6,966 618 41 (1 ) 7,624 2015 Operating revenues $ 16,491 $ 1,390 $ (439 ) $ 17,442 $ — $ 152 $ (105 ) $ 17,489 Depreciation and amortization 1,772 248 — 2,020 — 14 — 2,034 Interest income 19 2 1 22 — 6 (5 ) 23 Earnings from equity method investments 1 — — 1 — (1 ) — — Interest expense 697 77 — 774 — 69 (3 ) 840 Income taxes 1,305 21 — 1,326 — (132 ) — 1,194 Segment net income (loss) (a) (b) 2,186 215 — 2,401 — (32 ) (2 ) 2,367 Total assets 69,052 8,905 (397 ) 77,560 — 1,819 (1,061 ) 78,318 Gross property additions 5,124 1,005 — 6,129 — 40 — 6,169 (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.4 billion ( $2.4 billion after tax) in 2017, $428 million ( $264 million after tax) in 2016, and $365 million ( $226 million after tax) in 2015. See Note 3 under " Kemper County Energy Facility – Schedule and Cost Estimate " for additional information. (c) Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ( $20 million after tax) in 2017. See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. |
Financial data for products and services | Products and Services Electric Utilities' Revenues Year Retail Wholesale Other Total (in millions) 2017 $ 15,330 $ 2,426 $ 784 $ 18,540 2016 15,234 1,926 781 17,941 2015 14,987 1,798 657 17,442 Southern Company Gas' Revenues Year Gas Gas All Other Total (in millions) 2017 $ 3,024 $ 860 $ 36 $ 3,920 2016 1,266 354 32 1,652 |
SOUTHERN Co GAS | |
Segment Reporting Information [Line Items] | |
Financial data for business segments | Financial data for business segments for the successor year ended December 31, 2017 , the successor period of July 1, 2016 through December 31, 2016 , and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were as follows: Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (a) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Successor – Year ended December 31, 2017 Operating revenues $ 3,207 $ 860 $ 6 $ 71 $ 4,144 $ 10 $ (234 ) $ 3,920 Depreciation and 391 62 2 18 473 28 — 501 Operating income (loss) 650 113 (51 ) (10 ) 702 (37 ) — 665 Earnings from equity method investments — — — 103 103 3 — 106 Interest expense (153 ) (5 ) (7 ) (33 ) (198 ) (2 ) — (200 ) Income taxes (b) 178 24 — 61 263 104 — 367 Segment net income (loss) (b) 353 84 (57 ) 3 383 (140 ) — 243 Gross property 1,330 9 1 134 1,474 34 — 1,508 Successor – Total assets 19,358 2,147 1,096 2,241 24,842 12,184 (14,039 ) 22,987 Successor – July 1, 2016 through December 31, 2016 Operating revenues $ 1,342 $ 354 $ 24 $ 31 $ 1,751 $ 3 $ (102 ) $ 1,652 Depreciation and 185 35 1 9 230 8 — 238 Operating income (loss) 222 27 (2 ) (7 ) 240 (43 ) — 197 Earnings from equity — — — 58 58 2 — 60 Interest expense (105 ) (1 ) (3 ) (16 ) (125 ) 44 — (81 ) Income taxes 51 7 (3 ) 16 71 5 — 76 Segment net income (loss) 77 19 — 20 116 (2 ) — 114 Gross property 561 5 1 54 621 11 — 632 Successor – Total assets 19,453 2,084 1,127 2,211 24,875 11,145 (14,167 ) 21,853 Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (a) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Predecessor – January 1, 2016 through June 30, 2016 Operating revenues $ 1,575 $ 435 $ (32 ) $ 25 $ 2,003 $ 4 $ (102 ) $ 1,905 Depreciation and 178 11 1 9 199 7 — 206 Operating income (loss) 351 109 (69 ) (9 ) 382 (61 ) — 321 EBIT 353 109 (68 ) (6 ) 388 (60 ) — 328 Gross property additions 484 4 1 43 532 16 — 548 Predecessor – Year Ended December 31, 2015 Operating revenues $ 3,049 $ 835 $ 202 $ 55 $ 4,141 $ 11 $ (211 ) $ 3,941 Depreciation and 336 25 1 18 380 17 — 397 Operating income (loss) 571 152 112 (26 ) 809 (63 ) — 746 EBIT 581 152 110 (23 ) 820 (59 ) — 761 Gross property additions 957 7 2 27 993 34 — 1,027 Predecessor – Total 12,519 686 935 692 14,832 9,662 (9,740 ) 14,754 (a) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. Third Party Gross Revenues Intercompany Revenues Total Gross Revenues Less Gross Gas Costs Operating Revenues (in millions) Successor – Year Ended $ 6,152 $ 481 $ 6,633 $ 6,627 $ 6 Su ccessor – July 1, 2016 through 5,807 333 6,140 6,116 24 (in millions) Predecessor – January 1, 2016 through $ 2,500 $ 143 $ 2,643 $ 2,675 $ (32 ) Predecessor – Year Ended December 31, 2015 6,286 408 6,694 6,492 202 (b) Includes the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. |
Noncontrolling Interest (Tables
Noncontrolling Interest (Tables) - SOUTHERN POWER CO | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Line Items] | |
Redeemable noncontrolling interest | The following table presents the changes in redeemable noncontrolling interests for the years ended December 31: 2017 2016 2015 (in millions) Beginning balance $ 164 $ 43 $ 39 Net income attributable to redeemable noncontrolling interests 2 4 2 Distributions to redeemable noncontrolling interests (2 ) (1 ) — Capital contributions from redeemable noncontrolling interests 2 118 2 Redemption of redeemable noncontrolling interests (59 ) — — Reclassification to non-redeemable noncontrolling interests (114 ) — — Change in fair value of redeemable noncontrolling interests 7 — — Ending balance $ — $ 164 $ 43 |
Condensed income statement | The following table presents the attribution of net income to the Company and the noncontrolling interests for the years ended December 31: 2017 2016 2015 (in millions) Net income $ 1,117 $ 374 $ 229 Less: Net income attributable to noncontrolling interests 44 32 12 Less: Net income attributable to redeemable noncontrolling interests 2 4 2 Net income attributable to the Company $ 1,071 $ 338 $ 215 |
Quarterly Financial Informati44
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2017 and 2016 is as follows: Consolidated Net Income Attributable to Southern Company Per Common Share Operating Revenues Operating Income Basic Earnings Diluted Earnings Trading Price Range Quarter Ended Dividends High Low (in millions) March 2017 $ 5,771 $ 1,306 $ 658 $ 0.66 $ 0.66 $ 0.5600 $ 51.47 $ 47.57 June 2017 5,430 (1,594 ) (1,381 ) (1.38 ) (1.37 ) 0.5800 51.97 47.87 September 2017 6,201 2,045 1,069 1.07 1.06 0.5800 50.80 46.71 December 2017 5,629 794 496 0.49 0.49 0.5800 53.51 47.92 March 2016 $ 3,992 $ 940 $ 489 $ 0.53 $ 0.53 $ 0.5425 $ 51.73 $ 46.00 June 2016 4,459 1,185 623 0.67 0.66 0.5600 53.64 47.62 September 2016 6,264 1,917 1,139 1.18 1.17 0.5600 54.64 50.00 December 2016 5,181 587 197 0.20 0.20 0.5600 52.23 46.20 |
ALABAMA POWER CO | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2017 $ 1,382 $ 376 $ 174 June 2017 1,484 454 230 September 2017 1,740 616 325 December 2017 1,433 268 119 March 2016 $ 1,331 $ 333 $ 156 June 2016 1,444 430 213 September 2016 1,785 650 351 December 2016 1,329 252 102 |
GEORGIA POWER CO | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2017 $ 1,832 $ 501 $ 260 June 2017 2,048 639 347 September 2017 2,546 1,034 580 December 2017 1,884 470 227 March 2016 $ 1,872 $ 509 $ 269 June 2016 2,051 656 349 September 2016 2,698 1,054 599 December 2016 1,762 258 113 |
GULF POWER CO | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in millions) March 2017 $ 350 $ 46 $ 18 June 2017 357 75 35 September 2017 437 115 63 December 2017 372 53 19 March 2016 $ 335 $ 65 $ 29 June 2016 365 74 34 September 2016 436 90 45 December 2016 349 54 23 |
MISSISSIPPI POWER CO | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) After Dividends on Preferred Stock (in millions) March 2017 $ 272 $ (62 ) $ (20 ) June 2017 303 (2,954 ) (2,054 ) September 2017 341 51 40 December 2017 271 (177 ) (556 ) March 2016 $ 257 $ (10 ) $ 11 June 2016 277 (28 ) 2 September 2016 352 9 26 December 2016 277 (166 ) (89 ) |
SOUTHERN POWER CO | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2017 and 2016 is as follows: Quarter Ended Operating Revenues Operating Income Income Tax (Benefit) Net Income Attributable to the Company (in millions) March 2017 $ 450 $ 65 $ (52 ) $ 70 June 2017 529 112 (38 ) 82 September 2017 618 159 (39 ) 124 December 2017 (*) 478 32 (810 ) 795 March 2016 $ 315 $ 47 $ (23 ) $ 50 June 2016 373 81 (41 ) 89 September 2016 500 134 (102 ) 176 December 2016 389 28 (29 ) 23 (*) As a result of the Tax Reform Legislation, the Company recorded an income tax benefit of $ 743 million in the fourth quarter 2017. See Note 5 for additional information. |
SOUTHERN Co GAS | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 and for the predecessor period of January 1, 2016 through June 30, 2016 are as follows: Quarter Ended Operating Operating EBIT Net Income (Loss) Attributable to Southern Company Gas (in millions) Successor - 2017 March 2017 $ 1,560 $ 391 $ 435 $ 239 June 2017 716 96 128 49 September 2017 (a) 565 68 118 15 December 2017 (a)(b) 1,079 110 129 (60 ) Predecessor - January 1, 2016 through June 30, 2016 (in millions) March 2016 $ 1,334 $ 348 $ 351 $ 182 June 2016 571 (27 ) (23 ) (51 ) Successor - July 1, 2016 through December 31, 2016 (in millions) September 2016 $ 543 $ 12 $ 50 $ 4 December 2016 1,109 185 221 110 (a) Net income (loss) attributable to Southern Company Gas includes the impact of new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. (b) Net loss attributable to Southern Company Gas includes the impact of the Tax Reform Legislation. |
Summary of Significant Accoun45
Summary of Significant Accounting Policies - General (Details) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | 48 Months Ended | ||||||||||
Dec. 31, 2017USD ($)statesegmentutilityEmployee | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)statesegmentutilityEmployee | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2017USD ($)statesegmentutilityEmployee | |
Accounting Policies [Line Items] | ||||||||||||||
Other intangible assets, net of amortization | $ 873 | $ 970 | $ 970 | $ 873 | $ 970 | $ 873 | ||||||||
Number of traditional operating companies | segment | 4 | 4 | 4 | |||||||||||
Retail revenues | $ 15,330 | 15,234 | $ 14,987 | |||||||||||
Net income after dividends on preferred and preference stock | $ 496 | $ 1,069 | $ (1,381) | $ 658 | 197 | $ 1,139 | $ 623 | $ 489 | 842 | 2,448 | 2,367 | |||
SOUTHERN Co GAS | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Other intangible assets, net of amortization | 280 | 366 | 366 | 280 | 366 | $ 280 | ||||||||
Net income after dividends on preferred and preference stock | $ (60) | 15 | 49 | 239 | 110 | 4 | 114 | $ 243 | ||||||
Number of states in which entity operates | state | 7 | 7 | 7 | |||||||||||
Number of natural gas distribution utilities | utility | 7 | 7 | 7 | |||||||||||
ALABAMA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Retail revenues | $ 5,458 | 5,322 | 5,234 | |||||||||||
Net income after dividends on preferred and preference stock | $ 119 | 325 | 230 | 174 | 102 | 351 | 213 | 156 | $ 848 | 822 | 785 | |||
Traditional Operating Companies | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Number of states in which entity operates | state | 4 | 4 | 4 | |||||||||||
GEORGIA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Environmental exit costs, assets previously disposed, liability for remediation | $ 22 | 17 | 17 | $ 22 | 17 | $ 22 | ||||||||
Retail revenues | 7,738 | 7,772 | 7,727 | |||||||||||
Net income after dividends on preferred and preference stock | 227 | 580 | 347 | 260 | 113 | 599 | 349 | 269 | $ 1,414 | 1,330 | 1,260 | |||
SOUTHERN POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Net income after dividends on preferred and preference stock | $ 795 | 124 | 82 | 70 | 23 | 176 | 89 | 50 | ||||||
Southern Company Services, Inc. | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Number of employee transfers | Employee | 538 | 538 | 538 | |||||||||||
MISSISSIPPI POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Retail revenues | $ 854 | 859 | 776 | |||||||||||
Net income after dividends on preferred and preference stock | $ (556) | $ 40 | $ (2,054) | $ (20) | $ (89) | $ 26 | $ 2 | $ 11 | (2,590) | (50) | (8) | |||
Restatement Adjustment | GEORGIA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Retail revenues | $ (75) | |||||||||||||
Net income after dividends on preferred and preference stock | $ (47) | |||||||||||||
Southern Company Services, Inc. | SOUTHERN Co GAS | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | $ 17 | 63 | ||||||||||||
Southern Company Services, Inc. | ALABAMA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | 479 | 460 | 438 | |||||||||||
Southern Company Services, Inc. | GEORGIA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | 625 | 606 | 585 | |||||||||||
Southern Company Services, Inc. | SOUTHERN POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | $ 218 | 193 | 146 | |||||||||||
Number of employee transfers | Employee | 538 | 538 | 538 | |||||||||||
Southern Company Services, Inc. | MISSISSIPPI POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | $ 140 | 231 | 295 | |||||||||||
Fuel Purchases | ALABAMA POWER CO | MISSISSIPPI POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | 8 | |||||||||||||
Power Pool [Member] | ALABAMA POWER CO | MISSISSIPPI POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Related party transaction, amount | 16 | $ 29 | $ 7 | |||||||||||
Other Regulatory Assets [Member] | GEORGIA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Amortization of regulatory assets | $ 54 | |||||||||||||
Storm damage reserves | GEORGIA POWER CO | ||||||||||||||
Accounting Policies [Line Items] | ||||||||||||||
Amortization of regulatory assets | $ 319 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Affiliate Transactions (Details) | Oct. 04, 2016USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($)location | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2016 |
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | $ 880,000,000 | $ 880,000,000 | $ 691,000,000 | $ 880,000,000 | ||||||
Purchased power | 863,000,000 | 750,000,000 | $ 645,000,000 | |||||||
Securities due within one year | 2,587,000,000 | 2,587,000,000 | 3,892,000,000 | 2,587,000,000 | ||||||
ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | 63,000,000 | 63,000,000 | 63,000,000 | 63,000,000 | ||||||
Cost of Purchased Power Affiliates | $ 158,000,000 | 168,000,000 | 180,000,000 | |||||||
Ownership percentage, equity method investment | 50.00% | |||||||||
Capital contributions from parent company | $ 361,000,000 | 260,000,000 | 22,000,000 | |||||||
Securities due within one year | 561,000,000 | 561,000,000 | 0 | 561,000,000 | ||||||
MISSISSIPPI POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | 26,000,000 | 26,000,000 | 33,000,000 | 26,000,000 | ||||||
Cost of Purchased Power Affiliates | 25,000,000 | 34,000,000 | 12,000,000 | |||||||
Capital contributions from parent company | $ 1,000,000,000 | 1,002,000,000 | 627,000,000 | 277,000,000 | ||||||
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | 0 | 0 | 301,000,000 | |||||||
Securities due within one year | 629,000,000 | 629,000,000 | 989,000,000 | 629,000,000 | ||||||
Long-term debt affiliated | 551,000,000 | 551,000,000 | 0 | 551,000,000 | ||||||
SOUTHERN Co GAS | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | 127,000,000 | 127,000,000 | 88,000,000 | 127,000,000 | ||||||
Intangible liabilities, accumulated amortization | 50,000,000 | |||||||||
Capital contributions from parent company | 1,085,000,000 | 103,000,000 | ||||||||
Securities due within one year | 22,000,000 | 22,000,000 | 157,000,000 | 22,000,000 | ||||||
GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | 71,000,000 | 71,000,000 | 67,000,000 | 71,000,000 | ||||||
Cost of Purchased Power Affiliates | 15,000,000 | 16,000,000 | 35,000,000 | |||||||
Purchased power | 155,000,000 | 142,000,000 | 135,000,000 | |||||||
Capital contributions from parent company | 2,000,000 | 20,000,000 | 4,000,000 | |||||||
Securities due within one year | 87,000,000 | 87,000,000 | 0 | 87,000,000 | ||||||
SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | 368,000,000 | 368,000,000 | 322,000,000 | 368,000,000 | ||||||
Deferred project development costs | 11,000,000 | 11,000,000 | 11,000,000 | |||||||
Purchased power | 27,000,000 | 21,000,000 | 21,000,000 | |||||||
Capital contributions from parent company | 0 | 1,850,000,000 | 646,000,000 | |||||||
Securities due within one year | 560,000,000 | 560,000,000 | 770,000,000 | 560,000,000 | ||||||
Repayments of debt | $ 40,000,000 | |||||||||
GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Other liabilities noncurrent | 199,000,000 | 199,000,000 | $ 128,000,000 | 199,000,000 | ||||||
Number of military bases for renewable generation | location | 2 | |||||||||
Cost of Purchased Power Affiliates | $ 622,000,000 | 518,000,000 | 575,000,000 | |||||||
Capital contributions from parent company | 431,000,000 | 594,000,000 | 62,000,000 | |||||||
Securities due within one year | 460,000,000 | 460,000,000 | 857,000,000 | 460,000,000 | ||||||
PowerSecure International, Inc. | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 11,000,000 | |||||||||
PowerSecure International, Inc. | GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | $ 119,000,000 | |||||||||
Southern Natural Gas Company, LLC | Southern Company Services, Inc. | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 32,000,000 | 136,000,000 | ||||||||
Cost of natural gas purchases | $ 27,000,000 | 142,000,000 | ||||||||
Southern Natural Gas Company, LLC | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 2,000,000 | 9,000,000 | ||||||||
Southern Natural Gas Company, LLC | SOUTHERN Co GAS | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 15,000,000 | 32,000,000 | ||||||||
Southern Natural Gas Company, LLC | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 7,000,000 | 25,000,000 | ||||||||
Southern Natural Gas Company, LLC | GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 35,000,000 | 102,000,000 | ||||||||
Southern Company Services, Inc. | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 479,000,000 | 460,000,000 | 438,000,000 | |||||||
Southern Company Services, Inc. | MISSISSIPPI POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 140,000,000 | 231,000,000 | 295,000,000 | |||||||
Southern Company Services, Inc. | SOUTHERN Co GAS | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 17,000,000 | 63,000,000 | ||||||||
Southern Company Services, Inc. | GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 81,000,000 | 80,000,000 | 81,000,000 | |||||||
Southern Company Services, Inc. | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 218,000,000 | 193,000,000 | 146,000,000 | |||||||
Southern Company Services, Inc. | GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 625,000,000 | 606,000,000 | 585,000,000 | |||||||
GEORGIA POWER CO | GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 11,000,000 | 8,000,000 | 12,000,000 | |||||||
MISSISSIPPI POWER CO | GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 31,000,000 | 26,000,000 | 27,000,000 | |||||||
ALABAMA POWER CO | GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Revenue requirements reimbursement | 11,000,000 | 12,000,000 | 14,000,000 | |||||||
GULF POWER CO | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Revenue requirements reimbursement | 11,000,000 | 12,000,000 | 14,000,000 | |||||||
GULF POWER CO | MISSISSIPPI POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | $ 31,000,000 | 26,000,000 | 27,000,000 | |||||||
GULF POWER CO | GEORGIA POWER CO | Plant Scherer Unit 3 (coal) | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Long-term purchase commitment, reimbursement percentage | 25.00% | |||||||||
SOUTHERN Co GAS | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | $ 17,000,000 | $ 119,000,000 | ||||||||
SOUTHERN Co GAS | GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | $ 10,000,000 | 22,000,000 | ||||||||
SOUTHERN POWER CO | GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 6,800,000 | |||||||||
SOUTHERN POWER CO | GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 235,000,000 | 265,000,000 | 179,000,000 | |||||||
Southern Nuclear Operating Company, Inc. | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 248,000,000 | 249,000,000 | 243,000,000 | |||||||
Southern Nuclear Operating Company, Inc. | GEORGIA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 675,000,000 | 666,000,000 | 681,000,000 | |||||||
Scenario, Plan | ALABAMA POWER CO | GULF POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Revenue requirements reimbursement | 10,000,000 | |||||||||
Scenario, Plan | GULF POWER CO | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Revenue requirements reimbursement | 61,000,000 | |||||||||
Southern Natural Gas Company, LLC | SOUTHERN Co GAS | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership percentage, equity method investment | 50.00% | |||||||||
Non-Fuel Expense | MISSISSIPPI POWER CO | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 9,000,000 | 13,000,000 | 11,000,000 | |||||||
Non-Fuel Expense | ALABAMA POWER CO | MISSISSIPPI POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 9,000,000 | 13,000,000 | 11,000,000 | |||||||
Non-Fuel Expense | GULF POWER CO | GEORGIA POWER CO | Plant Scherer Unit 3 (coal) | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Reimbursement Revenue | 11,000,000 | 8,000,000 | 12,000,000 | |||||||
Fuel Purchases | MISSISSIPPI POWER CO | ALABAMA POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 0 | 0 | 8,000,000 | |||||||
Fuel Purchases | ALABAMA POWER CO | MISSISSIPPI POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 8,000,000 | |||||||||
Purchased Power from Affiliates | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 233,000,000 | 258,000,000 | 219,000,000 | |||||||
Operating Lease PPA | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 81,000,000 | 109,000,000 | 109,000,000 | |||||||
Operations and Maintenance Expense | Southern Company Services, Inc. | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | 192,000,000 | 173,000,000 | 138,000,000 | |||||||
Electric Transmission | Southern Company Services, Inc. | SOUTHERN POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Related party transaction, amount | $ 13,000,000 | $ 11,000,000 | $ 11,000,000 | |||||||
Promissory Notes | Promissory Notes | MISSISSIPPI POWER CO | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Repayments of debt | 109,000,000 | $ 591,000,000 | ||||||||
Debt instrument, face amount | $ 150,000,000 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | 48 Months Ended | ||||
Jul. 31, 2016 | Dec. 31, 2019 | Dec. 31, 2017 | Dec. 31, 2017 | Jan. 11, 2018 | Dec. 31, 2016 | Aug. 29, 2016 | |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ (1,894) | $ (1,894) | $ 5,866 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Accumulated deferred income taxes | 6,842 | 6,842 | 14,092 | ||||
Other cost of removal obligations | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (2,684) | (2,684) | (2,774) | ||||
Deferred income tax credits | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (7,261) | (7,261) | (219) | ||||
Over recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (155) | (155) | (203) | ||||
Property damage reserves-liability | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (135) | (135) | (177) | ||||
Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (266) | (266) | (120) | ||||
Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 3,931 | 3,931 | 3,959 | ||||
AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 1,133 | 1,133 | 1,080 | ||||
Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 511 | 511 | 487 | ||||
Loss on reacquired debt | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 223 | 223 | 243 | ||||
Environmental remediation-asset | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 511 | 511 | 491 | ||||
Under recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 317 | 317 | 273 | ||||
Property damage reserves-asset | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 333 | 333 | 206 | ||||
Regulatory assets associated with the Kemper County energy facility | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 88 | 88 | 201 | ||||
Vacation pay | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 183 | 183 | 182 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 1 year | ||||||
Long-term debt fair value adjustment | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 138 | 138 | 155 | ||||
Deferred PPA charges | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 119 | 119 | 141 | ||||
Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 306 | 306 | 351 | ||||
Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 814 | 814 | 1,590 | ||||
Maximum | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Life of new issue | 50 years | ||||||
Power purchase agreement period | 6 years | ||||||
Maximum | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory liability, amortization period | 20 years | ||||||
Maximum | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 15 years | ||||||
Maximum | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 50 years | ||||||
Maximum | Asset Group 1 | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 10 years | ||||||
Maximum | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 48 years | ||||||
Maximum | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 80 years | ||||||
ALABAMA POWER CO | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Fuel hedging assets and liabilities, amortization period | 3 years 6 months | ||||||
Total assets (liabilities), net | $ (1,088) | (1,088) | 1,047 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Medicare drug subsidy obligation related to subsidiary | 13 | 13 | 16 | ||||
ALABAMA POWER CO | Other cost of removal obligations | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (609) | (609) | (684) | ||||
ALABAMA POWER CO | Deferred income tax credits | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (2,082) | (2,082) | (65) | ||||
ALABAMA POWER CO | Over recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 53 | 53 | 76 | ||||
ALABAMA POWER CO | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (7) | (7) | (23) | ||||
ALABAMA POWER CO | AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 12 | ||||||
ALABAMA POWER CO | Natural disaster reserve | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (38) | (38) | (69) | ||||
ALABAMA POWER CO | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 946 | 946 | 947 | ||||
ALABAMA POWER CO | AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (33) | (33) | |||||
ALABAMA POWER CO | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 51 | 51 | 50 | ||||
ALABAMA POWER CO | Loss on reacquired debt | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 62 | 62 | 68 | ||||
ALABAMA POWER CO | Under recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 142 | 142 | 0 | ||||
ALABAMA POWER CO | Vacation pay | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 70 | 70 | 69 | ||||
ALABAMA POWER CO | Nuclear outage | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 56 | 56 | 70 | ||||
ALABAMA POWER CO | Fuel-hedging-asset | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 7 | 7 | 1 | ||||
ALABAMA POWER CO | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 54 | 54 | 69 | ||||
ALABAMA POWER CO | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 11 years | ||||||
ALABAMA POWER CO | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 240 | 240 | 526 | ||||
ALABAMA POWER CO | Maximum | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Life of new issue | 50 years | ||||||
ALABAMA POWER CO | Maximum | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 15 years | ||||||
ALABAMA POWER CO | Maximum | Deferred income tax charges | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 15 years | ||||||
ALABAMA POWER CO | Maximum | Nuclear outage | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 10 years | ||||||
ALABAMA POWER CO | Maximum | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 50 years | ||||||
GEORGIA POWER CO | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 232 | 232 | 3,506 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Refueling cycles maximum period | 24 months | ||||||
GEORGIA POWER CO | Other cost of removal obligations | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 40 | 40 | 3 | ||||
GEORGIA POWER CO | Deferred income tax credits | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (3,248) | (3,248) | (121) | ||||
GEORGIA POWER CO | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (191) | (191) | (39) | ||||
GEORGIA POWER CO | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 1,313 | 1,313 | 1,348 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 14 years | ||||||
GEORGIA POWER CO | Deferred income tax charges | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 21 | 21 | |||||
GEORGIA POWER CO | AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 945 | 945 | 893 | ||||
GEORGIA POWER CO | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 119 | 119 | 97 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 24 months | ||||||
Amortization of regulatory assets | $ 54 | ||||||
GEORGIA POWER CO | Loss on reacquired debt | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 127 | 127 | 137 | ||||
GEORGIA POWER CO | Vacation pay | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 91 | 91 | 91 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 1 year | ||||||
GEORGIA POWER CO | Canceled Construction Projects | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 36 | 36 | 44 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 9 years | ||||||
GEORGIA POWER CO | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 146 | 146 | 166 | ||||
GEORGIA POWER CO | Obsolete Inventories of Retired Units | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 31 | 31 | |||||
GEORGIA POWER CO | Storm damage reserves | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 333 | 333 | 206 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Amortization of regulatory assets | 319 | ||||||
GEORGIA POWER CO | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 521 | 521 | 681 | ||||
Tax Cuts and Jobs Act of 2017, Deferred Tax Assets Related to CWIP | 145 | 145 | |||||
Tax Cuts and Jobs Act of 2017, Deferred Tax Liabilities | 626 | 626 | |||||
GEORGIA POWER CO | Plant Mitchell Unit 3 | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Net book value of planned units retirements | $ 10 | 10 | |||||
GEORGIA POWER CO | Maximum | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Life of new issue | 35 years | ||||||
GEORGIA POWER CO | Maximum | Deferred Income Tax Charge, AROs, Cost Of Removal Obligations, Deferred Income Tax Credits | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 65 years | ||||||
GEORGIA POWER CO | Maximum | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 10 years | ||||||
GEORGIA POWER CO | Scenario, Forecast | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Amortization of regulatory assets | $ 4 | ||||||
GULF POWER CO | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ (105) | (105) | 320 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory asset | $ 63 | ||||||
Life of new issue | 40 years | ||||||
GULF POWER CO | Over Under Recovered Regulatory Clause Revenues | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 1 year | ||||||
GULF POWER CO | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ (458) | (458) | (2) | ||||
GULF POWER CO | Other cost of removal obligations | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (221) | (221) | (278) | ||||
GULF POWER CO | Deferred income tax credits | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Accumulated deferred income taxes | 71 | 71 | |||||
GULF POWER CO | Over recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (11) | (11) | (23) | ||||
GULF POWER CO | Property damage reserves-liability | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (40) | (40) | (40) | ||||
GULF POWER CO | AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 7 | ||||||
GULF POWER CO | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 166 | 166 | 160 | ||||
GULF POWER CO | AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 13 | 13 | |||||
GULF POWER CO | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 36 | 36 | 18 | ||||
GULF POWER CO | Loss on reacquired debt | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 17 | 17 | 18 | ||||
GULF POWER CO | Environmental remediation-asset | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 52 | 52 | 44 | ||||
GULF POWER CO | Deferred Return On Transmission Upgrades | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 25 | 25 | 25 | ||||
GULF POWER CO | Vacation pay | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 1 year | ||||||
GULF POWER CO | Deferred PPA charges | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 119 | 119 | 141 | ||||
GULF POWER CO | Ash Pond Closure | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 80 | 80 | 75 | ||||
GULF POWER CO | Fuel Hedging Assets and Liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 4 years | ||||||
GULF POWER CO | Fuel-hedging-asset | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 21 | 21 | 24 | ||||
GULF POWER CO | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 65 | 65 | 66 | ||||
GULF POWER CO | Regulatory asset, offset to other cost of removal | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 0 | 0 | 29 | ||||
GULF POWER CO | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 31 | 31 | 56 | ||||
GULF POWER CO | Maximum | Deferred income tax credits | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 65 years | ||||||
GULF POWER CO | Maximum | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 14 years | ||||||
GULF POWER CO | Maximum | Deferred PPA charges | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 6 years | ||||||
GULF POWER CO | Maximum | Deferred Income Tax Charge, AROs, Cost Of Removal Obligations, Deferred Income Tax Credits | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 65 years | ||||||
MISSISSIPPI POWER CO | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ (42) | (42) | 737 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 5 years | ||||||
MISSISSIPPI POWER CO | Deferred Credits Related To Income Taxes [Member] | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (377) | (377) | (9) | ||||
Deferred tax assets from tax reform | 375 | 375 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Tax Cuts and Jobs Act of 2017, Protected Deferred Tax Assets | 273 | 273 | |||||
Tax Cuts and Jobs Act of 2017, Unprotected Deferred Tax Assets | 102 | 102 | |||||
MISSISSIPPI POWER CO | Other cost of removal obligations | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (178) | (178) | (170) | ||||
MISSISSIPPI POWER CO | Property damage reserves-liability | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (57) | (57) | (68) | ||||
MISSISSIPPI POWER CO | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 0 | 0 | (1) | ||||
MISSISSIPPI POWER CO | Kemper IGCC | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 88 | 88 | 194 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory asset | 114 | 114 | |||||
Regulatory assets, noncurrent | $ 26 | 26 | |||||
MISSISSIPPI POWER CO | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 15 years | ||||||
MISSISSIPPI POWER CO | AROs | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 95 | 95 | 83 | ||||
MISSISSIPPI POWER CO | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 28 | 28 | 28 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 50 years | ||||||
MISSISSIPPI POWER CO | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 48 years | ||||||
MISSISSIPPI POWER CO | Remaining net book value of retired assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 44 | 44 | 53 | ||||
MISSISSIPPI POWER CO | Property Tax | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 43 | 43 | 37 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 12 months | ||||||
MISSISSIPPI POWER CO | Deferred Income Tax Charge | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 36 | 36 | 362 | ||||
MISSISSIPPI POWER CO | Retiree Benefit Plans - Regulatory Assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 174 | 174 | 173 | ||||
MISSISSIPPI POWER CO | ECO Carryforward [Member] | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 26 | 26 | 22 | ||||
MISSISSIPPI POWER CO | Kemper IGCC | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory asset | 114 | 114 | |||||
MISSISSIPPI POWER CO | Kemper IGCC | Deferred Credits Related To Income Taxes [Member] | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Deferred tax assets from tax reform | $ 129 | 129 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 8 years | ||||||
Tax Cuts and Jobs Act of 2017, Unprotected Deferred Tax Assets | $ 54 | 54 | |||||
MISSISSIPPI POWER CO | Plant Daniel Units 3 and 4 | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 10 years | ||||||
MISSISSIPPI POWER CO | Plant Daniel Units 3 and 4 | Plant Daniel Units 3 and 4 | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 36 | 36 | 33 | ||||
MISSISSIPPI POWER CO | Amortization Period One | Fuel Hedging Assets and Liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 8 years | ||||||
MISSISSIPPI POWER CO | Amortization Period Two | Fuel Hedging Assets and Liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 6 years | ||||||
SOUTHERN Co GAS | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ (1,879) | (1,879) | (715) | ||||
SOUTHERN Co GAS | Environmental Remediation | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | 410 | 410 | 411 | ||||
SOUTHERN Co GAS | Other cost of removal obligations | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (1,646) | (1,646) | (1,616) | ||||
SOUTHERN Co GAS | Deferred income tax credits | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (1,063) | (1,063) | (22) | ||||
SOUTHERN Co GAS | Over recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (144) | (144) | (104) | ||||
SOUTHERN Co GAS | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | (21) | (21) | (39) | ||||
SOUTHERN Co GAS | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 79 | 79 | 58 | ||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 12 months | ||||||
SOUTHERN Co GAS | Under recovered regulatory clause revenues | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 98 | 98 | 118 | ||||
SOUTHERN Co GAS | Vacation pay | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 1 year | ||||||
SOUTHERN Co GAS | Long-term debt fair value adjustment | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 270 | 270 | 325 | ||||
SOUTHERN Co GAS | Environmental Remediation | |||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||
Total assets (liabilities), net | $ 138 | 138 | $ 154 | ||||
SOUTHERN Co GAS | Over Under Recovered Regulatory Clause Revenues | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 8 years | ||||||
SOUTHERN Co GAS | Maximum | Retiree Benefit Plans | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 15 years | ||||||
SOUTHERN Co GAS | Maximum | Other regulatory assets | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 10 years | ||||||
SOUTHERN Co GAS | Maximum | Long-term debt fair value adjustment | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 21 years | ||||||
SOUTHERN Co GAS | Maximum | Financial Instrument Hedging | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 2 years | ||||||
SOUTHERN Co GAS | Maximum | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 20 years | ||||||
SOUTHERN Co GAS | Maximum | Deferred Income Tax Charges and Other Cost of Removal Obligations | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 80 years | ||||||
SOUTHERN Co GAS | Minimum | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Regulatory amortization period | 4 years | ||||||
Subsequent Event | GEORGIA POWER CO | Other regulatory liabilities | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Customer Refund Liability, Noncurrent | $ 188 | ||||||
Retail [Member] | MISSISSIPPI POWER CO | Kemper IGCC | Deferred Credits Related To Income Taxes [Member] | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Tax Cuts and Jobs Act of 2017, Unprotected Deferred Tax Assets | $ 38 | 38 | |||||
Wholesale [Member] | MISSISSIPPI POWER CO | Kemper IGCC | Deferred Credits Related To Income Taxes [Member] | |||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||||||
Tax Cuts and Jobs Act of 2017, Unprotected Deferred Tax Assets | $ 16 | $ 16 |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Government Grants, Revenue, Taxes, Concentration Risk (Details) - USD ($) $ in Millions | Apr. 08, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2010 |
Accounting Policies [Line Items] | ||||||||
Deferred income tax assets | $ 9,495 | $ 8,424 | $ 9,495 | $ 9,495 | ||||
Maximum | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.00% | |||||||
Maximum percentage of uncollectible accounts (less than) | 1.00% | |||||||
ALABAMA POWER CO | ||||||||
Accounting Policies [Line Items] | ||||||||
Deferred income tax assets | 1,544 | $ 1,028 | 1,544 | 1,544 | ||||
ALABAMA POWER CO | Maximum | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.00% | |||||||
Maximum percentage of uncollectible accounts (less than) | 1.00% | |||||||
GEORGIA POWER CO | ||||||||
Accounting Policies [Line Items] | ||||||||
Federal tax credits | $ 87 | |||||||
Deferred income tax assets | 2,382 | $ 1,886 | 2,382 | 2,382 | ||||
GEORGIA POWER CO | Maximum | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.00% | |||||||
Maximum percentage of uncollectible accounts (less than) | 1.00% | |||||||
GULF POWER CO | ||||||||
Accounting Policies [Line Items] | ||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||
Deferred income tax assets | 244 | $ 275 | 244 | 244 | ||||
GULF POWER CO | Minimum | ||||||||
Accounting Policies [Line Items] | ||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||
GULF POWER CO | Maximum | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.00% | |||||||
Maximum percentage of uncollectible accounts (less than) | 1.00% | |||||||
MISSISSIPPI POWER CO | ||||||||
Accounting Policies [Line Items] | ||||||||
Percentage of wholesale customers to operating revenue | 19.30% | |||||||
Period of contract cancellation notices of wholesale customers | 10 years | |||||||
Deferred income tax assets | 1,022 | $ 1,173 | 1,022 | 1,022 | ||||
Grants received from Department of Energy | 382 | |||||||
MISSISSIPPI POWER CO | Maximum | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.00% | |||||||
Maximum percentage of uncollectible accounts (less than) | 1.00% | |||||||
MISSISSIPPI POWER CO | Kemper IGCC | ||||||||
Accounting Policies [Line Items] | ||||||||
Grants expected to be received from Department of Energy | $ 2 | $ 270 | ||||||
Grants received from Department of Energy | $ 137 | 245 | ||||||
SOUTHERN POWER CO | ||||||||
Accounting Policies [Line Items] | ||||||||
Deferred income tax assets | 2,937 | $ 2,693 | $ 2,937 | 2,937 | ||||
Reduction in tax basis of assets | 50.00% | |||||||
SOUTHERN POWER CO | Sales Revenue, Goods, Net | GEORGIA POWER CO | Customer Concentration Risk | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 11.30% | 16.50% | 15.80% | |||||
SOUTHERN POWER CO | Sales Revenue, Goods, Net | Duke Energy Corporation | Customer Concentration Risk | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 6.70% | 7.80% | 8.20% | |||||
SOUTHERN POWER CO | Sales Revenue, Goods, Net | Morgan Stanley Capital Group | Customer Concentration Risk | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 4.50% | |||||||
SOUTHERN POWER CO | Sales Revenue, Goods, Net | San Diego Gas & Electric Company | Customer Concentration Risk | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 5.70% | |||||||
SOUTHERN POWER CO | Sales Revenue, Goods, Net | Florida Power & Light Company | Customer Concentration Risk | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.70% | |||||||
SOUTHERN Co GAS | ||||||||
Accounting Policies [Line Items] | ||||||||
Deferred income tax assets | 598 | $ 849 | $ 598 | $ 598 | ||||
Period for collection of revenue prior to billings | 24 months | |||||||
Excise taxes collected | 32 | $ 100 | ||||||
SOUTHERN Co GAS | Maximum | ||||||||
Accounting Policies [Line Items] | ||||||||
Maximum revenue from a single customer or industry (more than) | 10.00% | |||||||
Maximum percentage of uncollectible accounts (less than) | 1.00% | |||||||
SOUTHERN Co GAS | Predecessor | ||||||||
Accounting Policies [Line Items] | ||||||||
Excise taxes collected | $ 57 | $ 103 | ||||||
Investment Tax And Other Credit Carryforward | GEORGIA POWER CO | ||||||||
Accounting Policies [Line Items] | ||||||||
Deferred income tax assets | $ 495 | |||||||
Included In Operating Expenses | SOUTHERN Co GAS | ||||||||
Accounting Policies [Line Items] | ||||||||
Excise taxes collected | $ 31 | $ 98 | ||||||
Included In Operating Expenses | SOUTHERN Co GAS | Predecessor | ||||||||
Accounting Policies [Line Items] | ||||||||
Excise taxes collected | $ 56 | $ 101 |
Summary of Significant Accoun49
Summary of Significant Accounting Policies - Property, Plant, and Equipment (Details) $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jul. 31, 2016 | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($)Property | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Generation | $ 48,836 | $ 51,279 | $ 48,836 | |||
Transmission | 11,156 | 11,562 | 11,156 | |||
Distribution | 18,418 | 19,239 | 18,418 | |||
General | 4,629 | 4,276 | 4,629 | |||
Plant acquisition adjustment | 126 | 126 | 126 | |||
Electric Utility Plant in Service | 83,165 | 86,482 | 83,165 | |||
Transportation and distribution | 11,996 | 13,078 | 11,996 | |||
Utility plant in service | 95,161 | 99,560 | 95,161 | |||
Information technology equipment and software | 544 | 752 | 544 | |||
Communications equipment | 424 | 456 | 424 | |||
Storage facilities | 1,463 | 1,598 | 1,463 | |||
Other | 824 | 1,176 | 824 | |||
Other plant in service | 3,255 | 3,982 | 3,255 | |||
Total plant in service | 98,416 | 103,542 | 98,416 | |||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Less: Accumulated amortization | (69) | (72) | (69) | |||
Balance, net of amortization | 144 | 201 | 144 | |||
Accrued property additions at year-end | 985 | 1,300 | $ 844 | |||
Capital Lease Obligations | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Non-cash property additions recognized | 162 | 18 | 13 | |||
Office building | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Capital leased assets, gross | 61 | 216 | 61 | |||
Nitrogen plant | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Capital leased assets, gross | 83 | 0 | 83 | |||
Computer-related equipment | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Capital leased assets, gross | 63 | 51 | 63 | |||
Gas pipeline | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Capital leased assets, gross | 6 | 6 | 6 | |||
SOUTHERN POWER CO | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | $ 32 | 251 | 257 | |||
Alabama Power and Georgia Power | ||||||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Refueling cycles for minimum period | 18 months | |||||
Refueling cycles maximum period | 24 months | |||||
SOUTHERN Co GAS | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Period for collection of revenue prior to billings | 24 months | |||||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Utility plant in service | 11,996 | $ 13,079 | 11,996 | |||
Information technology equipment and software | 324 | 366 | 324 | |||
Storage facilities | 1,463 | 1,599 | 1,463 | |||
Other | 725 | 789 | 725 | |||
Other plant in service | 2,512 | 2,754 | 2,512 | |||
Total plant in service | 14,508 | 15,833 | 14,508 | |||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | 63 | $ 135 | ||||
SOUTHERN Co GAS | Predecessor | ||||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | $ 41 | 48 | ||||
ALABAMA POWER CO | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Number of units for which outage operations and maintenance expenses accrued | Property | 2 | |||||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Generation | 13,551 | $ 14,213 | 13,551 | |||
Transmission | 3,921 | 4,119 | 3,921 | |||
Distribution | 6,707 | 7,034 | 6,707 | |||
General | 1,840 | 1,948 | 1,840 | |||
Plant acquisition adjustment | 12 | 12 | 12 | |||
Total plant in service | 26,031 | 27,326 | 26,031 | |||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | $ 245 | 84 | 121 | |||
Period over which deferred costs are being amortized to nuclear operations and maintenance expenses | 18 months | |||||
GEORGIA POWER CO | ||||||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Generation | 16,668 | $ 17,038 | 16,668 | |||
Transmission | 5,779 | 5,947 | 5,779 | |||
Distribution | 9,553 | 9,978 | 9,553 | |||
General | 1,813 | 1,870 | 1,813 | |||
Plant acquisition adjustment | 28 | 28 | 28 | |||
Total plant in service | 33,841 | $ 34,861 | 33,841 | |||
Refueling cycles for minimum period | 18 months | |||||
Refueling cycles maximum period | 24 months | |||||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | $ 550 | 336 | 387 | |||
GULF POWER CO | ||||||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Generation | 3,001 | 3,005 | 3,001 | |||
Transmission | 706 | 720 | 706 | |||
Distribution | 1,241 | 1,282 | 1,241 | |||
General | 191 | 188 | 191 | |||
Plant acquisition adjustment | 1 | 1 | 1 | |||
Total plant in service | 5,140 | 5,196 | 5,140 | |||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | 31 | 33 | 20 | |||
MISSISSIPPI POWER CO | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Regulatory amortization period | 5 years | |||||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||||||
Generation | 2,632 | 2,801 | 2,632 | |||
Transmission | 712 | 737 | 712 | |||
Distribution | 916 | 946 | 916 | |||
General | 520 | 204 | 520 | |||
Plant acquisition adjustment | 85 | 85 | 85 | |||
Total plant in service | $ 4,865 | 4,773 | 4,865 | |||
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract] | ||||||
Accrued property additions at year-end | $ 32 | $ 78 | $ 105 | |||
Maximum | SOUTHERN POWER CO | Natural Gas Generating Facility | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Public utilities, property, plant and equipment, generation, useful life | 45 years | |||||
Maximum | SOUTHERN POWER CO | Biomass Generating Facility | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Public utilities, property, plant and equipment, generation, useful life | 40 years | |||||
Maximum | SOUTHERN POWER CO | Solar Generating Facility | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Public utilities, property, plant and equipment, generation, useful life | 35 years | |||||
Maximum | SOUTHERN POWER CO | Wind Generating Facility | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Public utilities, property, plant and equipment, generation, useful life | 30 years |
Summary of Significant Accoun50
Summary of Significant Accounting Policies - Depreciation and Amortization (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jul. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2017 | |
Property, Plant and Equipment [Line Items] | |||||
Accumulated depreciation PPE | $ 31,457 | $ 29,852 | |||
Other cost of removal obligations | $ 2,684 | $ 2,748 | |||
Utility Plant in Service | |||||
Property, Plant and Equipment [Line Items] | |||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.90% | 3.00% | 3.00% | ||
Accumulated depreciation PPE | $ 30,800 | $ 29,300 | |||
Other Plant in Service | |||||
Property, Plant and Equipment [Line Items] | |||||
Accumulated depreciation PPE | $ 673 | $ 550 | |||
Minimum | Other Plant in Service | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 2 years | ||||
Maximum | Other Plant in Service | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 65 years | ||||
MISSISSIPPI POWER CO | |||||
Property, Plant and Equipment [Line Items] | |||||
Regulatory amortization period | 5 years | ||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.70% | 4.20% | 4.70% | ||
Accumulated depreciation PPE | $ 1,325 | $ 1,289 | |||
Other cost of removal obligations | $ 178 | $ 170 | |||
GULF POWER CO | |||||
Property, Plant and Equipment [Line Items] | |||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.50% | 3.50% | 3.60% | ||
Accumulated depreciation PPE | $ 1,461 | $ 1,382 | |||
Other cost of removal obligations | 221 | 249 | |||
SOUTHERN POWER CO | |||||
Property, Plant and Equipment [Line Items] | |||||
Accumulated depreciation PPE | $ 1,910 | 1,484 | |||
SOUTHERN POWER CO | Maximum | Natural Gas Generating Facility | |||||
Property, Plant and Equipment [Line Items] | |||||
Public utilities, property, plant and equipment, generation, useful life | 45 years | ||||
SOUTHERN POWER CO | Maximum | Solar Generating Facility | |||||
Property, Plant and Equipment [Line Items] | |||||
Public utilities, property, plant and equipment, generation, useful life | 35 years | ||||
SOUTHERN POWER CO | Maximum | Wind Generating Facility | |||||
Property, Plant and Equipment [Line Items] | |||||
Public utilities, property, plant and equipment, generation, useful life | 30 years | ||||
SOUTHERN Co GAS | |||||
Property, Plant and Equipment [Line Items] | |||||
Accumulated depreciation PPE | $ 4,596 | 4,439 | |||
Other cost of removal obligations | $ 1,646 | $ 1,616 | |||
SOUTHERN Co GAS | Utility Plant in Service | |||||
Property, Plant and Equipment [Line Items] | |||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.90% | 2.80% | |||
SOUTHERN Co GAS | Utility Plant in Service | Predecessor | |||||
Property, Plant and Equipment [Line Items] | |||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.70% | ||||
SOUTHERN Co GAS | Minimum | Transportation Equipment | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 5 years | ||||
SOUTHERN Co GAS | Minimum | Storage Facilities | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 40 years | ||||
SOUTHERN Co GAS | Maximum | Transportation Equipment | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 15 years | ||||
SOUTHERN Co GAS | Maximum | Storage Facilities | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 60 years | ||||
SOUTHERN Co GAS | Maximum | Other Assets | |||||
Property, Plant and Equipment [Line Items] | |||||
Plant in service, estimated useful lives | 65 years | ||||
GEORGIA POWER CO | |||||
Property, Plant and Equipment [Line Items] | |||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.70% | 2.80% | 2.70% | ||
Regulatory liability amortization | $ 14 | $ 14 | $ 14 | ||
Accumulated depreciation PPE | 11,704 | 11,317 | |||
ALABAMA POWER CO | |||||
Property, Plant and Equipment [Line Items] | |||||
Accumulated depreciation PPE | 9,563 | 9,112 | |||
Other cost of removal obligations | $ 609 | $ 684 | |||
ALABAMA POWER CO | Utility Plant in Service | |||||
Property, Plant and Equipment [Line Items] | |||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.90% | 3.00% | 2.90% | ||
Settlement Agreement | GULF POWER CO | |||||
Property, Plant and Equipment [Line Items] | |||||
Other cost of removal obligations | $ 62.5 |
Summary of Significant Accoun51
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at beginning of year | $ 4,514 | $ 3,759 | |
Liabilities incurred | 16 | 66 | |
Liabilities settled | (177) | (171) | |
Liabilities settled | (177) | (171) | $ (37) |
Accretion | 179 | 162 | |
Cash flow revisions | 292 | 698 | |
Balance at end of year | 4,824 | 4,514 | 3,759 |
ALABAMA POWER CO | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at beginning of year | 1,533 | 1,448 | |
Liabilities incurred | 0 | 5 | |
Liabilities settled | (26) | (25) | |
Accretion | 77 | 73 | |
Cash flow revisions | 125 | 32 | |
Balance at end of year | 1,709 | 1,533 | 1,448 |
GEORGIA POWER CO | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at beginning of year | 2,532 | 1,916 | |
Liabilities incurred | 4 | 0 | |
Liabilities settled | (120) | (123) | (29) |
Accretion | 89 | 77 | |
Cash flow revisions | 133 | 662 | |
Balance at end of year | 2,638 | 2,532 | 1,916 |
GULF POWER CO | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at beginning of year | 136 | 130 | |
Liabilities incurred | 0 | 1 | |
Liabilities settled | (8) | (1) | |
Accretion | 2 | 4 | |
Cash flow revisions | 12 | 2 | |
Balance at end of year | 142 | 136 | 130 |
MISSISSIPPI POWER CO | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at beginning of year | 179 | 177 | |
Liabilities incurred | 0 | 15 | |
Liabilities settled | (23) | (23) | |
Accretion | 5 | 5 | |
Cash flow revisions | 13 | 5 | |
Balance at end of year | 174 | 179 | 177 |
SOUTHERN POWER CO | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at beginning of year | 64 | 21 | |
Liabilities incurred | 6 | 42 | |
Accretion | 4 | 1 | |
Cash flow revisions | 4 | 0 | |
Balance at end of year | $ 78 | $ 64 | $ 21 |
Summary of Significant Accoun52
Summary of Significant Accounting Policies - Nuclear Decommissiong (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2013 | Dec. 31, 2014 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | $ 1,832 | $ 1,606 | |||
Proceeds from sale of securities held in external trust funds | 800 | 1,200 | $ 1,400 | ||
Increase (decrease) in fair value of securities related to nuclear decommissioning | 233 | 114 | 11 | ||
Plant Farley | |||||
Decommissioning | |||||
Total site study costs | 1,442 | ||||
Plant Farley | Spent fuel management | |||||
Decommissioning | |||||
Total site study costs | 0 | ||||
Plant Hatch | |||||
Decommissioning | |||||
Total site study costs | 902 | ||||
Plant Vogtle (nuclear) Units 1 and 2 | |||||
Decommissioning | |||||
Total site study costs | 804 | ||||
Equity Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 1,100 | 878 | |||
Debt Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 725 | 685 | |||
Other Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 47 | 41 | |||
Unrealized Loss | Securities Held in Funds | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Increase (decrease) in fair value of securities related to nuclear decommissioning | (48) | ||||
Unrealized Gain | Securities Held in Funds | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Increase (decrease) in fair value of securities related to nuclear decommissioning | 181 | 83 | |||
ALABAMA POWER CO | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Decommissioning fund investments net of foreign currency | 902 | 790 | |||
Nuclear decommissioning trusts, at fair value | 903 | 792 | |||
Proceeds from sale of securities held in external trust funds | 237 | 351 | 438 | ||
Increase (decrease) in fair value of securities related to nuclear decommissioning | 125 | 76 | 8 | ||
Accumulated Provisions for Decommissioning | |||||
Accumulated Provisions for Decommissioning | 920 | 809 | |||
Decommissioning | |||||
Total site study costs | $ 1,442 | ||||
Significant assumption of inflation rate used to determine the costs for rate making (as percent) | 4.50% | ||||
Significant assumption of trust earnings rate used to determine the costs for rate making (as percent) | 7.00% | ||||
ALABAMA POWER CO | Accumulated provisions for the external decommissioning trust funds | |||||
Accumulated Provisions for Decommissioning | |||||
Accumulated Provisions for Decommissioning | 790 | ||||
ALABAMA POWER CO | Accumulated Provisions for Decommissioning Internal Reserves | |||||
Accumulated Provisions for Decommissioning | |||||
Accumulated Provisions for Decommissioning | $ 18 | 19 | |||
ALABAMA POWER CO | Plant Farley | Plant Farley | |||||
Decommissioning | |||||
Beginning Year | 2,037 | ||||
Completion Year | 2,076 | ||||
ALABAMA POWER CO | Plant Farley | Accumulated provisions for the external decommissioning trust funds | |||||
Accumulated Provisions for Decommissioning | |||||
Accumulated Provisions for Decommissioning | $ 902 | 790 | |||
ALABAMA POWER CO | Plant Farley | Radiated structures | |||||
Decommissioning | |||||
Total site study costs | 1,362 | ||||
ALABAMA POWER CO | Plant Farley | Non-radiated structures | |||||
Decommissioning | |||||
Total site study costs | 80 | ||||
ALABAMA POWER CO | Equity Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 644 | 552 | |||
ALABAMA POWER CO | Debt Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 223 | 208 | |||
ALABAMA POWER CO | Other Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 35 | 30 | |||
ALABAMA POWER CO | Securities Held in Funds | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Increase (decrease) in fair value of securities related to nuclear decommissioning | (34) | 57 | |||
ALABAMA POWER CO | Unrealized Gain | Securities Held in Funds | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Increase (decrease) in fair value of securities related to nuclear decommissioning | 98 | ||||
GEORGIA POWER CO | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Environmental regulatory assets | 49 | 35 | |||
Fair market value of fund's securities on loan under the Funds' managers' securities lending program | 76 | 56 | |||
Fair value of collateral received | 77 | 58 | |||
Decommissioning fund investments net of foreign currency | 929 | 814 | |||
Nuclear decommissioning trusts, at fair value | 929 | 814 | |||
Increase (decrease) in fair value of securities related to nuclear decommissioning | $ 108 | 38 | 3 | ||
Decommissioning | |||||
Significant assumption of inflation rate used to determine the costs for rate making (as percent) | 2.40% | ||||
Significant assumption of trust earnings rate used to determine the costs for rate making (as percent) | 4.40% | ||||
GEORGIA POWER CO | Plant Hatch | |||||
Decommissioning | |||||
Beginning Year | 2,034 | ||||
Completion Year | 2,075 | ||||
Total site study costs | $ 902 | ||||
Amount expensed for rate making purpose | $ 4 | ||||
GEORGIA POWER CO | Plant Hatch | Accumulated provisions for the external decommissioning trust funds | |||||
Accumulated Provisions for Decommissioning | |||||
Accumulated Provisions for Decommissioning | 583 | 511 | |||
GEORGIA POWER CO | Plant Hatch | Radiated structures | |||||
Decommissioning | |||||
Total site study costs | 678 | ||||
GEORGIA POWER CO | Plant Hatch | Spent fuel management | |||||
Decommissioning | |||||
Total site study costs | 160 | ||||
GEORGIA POWER CO | Plant Hatch | Non-radiated structures | |||||
Decommissioning | |||||
Total site study costs | $ 64 | ||||
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | |||||
Decommissioning | |||||
Beginning Year | 2,047 | ||||
Completion Year | 2,079 | ||||
Total site study costs | $ 804 | ||||
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | Accumulated provisions for the external decommissioning trust funds | |||||
Accumulated Provisions for Decommissioning | |||||
Accumulated Provisions for Decommissioning | 346 | 303 | |||
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | Radiated structures | |||||
Decommissioning | |||||
Total site study costs | 568 | ||||
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | Spent fuel management | |||||
Decommissioning | |||||
Total site study costs | 147 | ||||
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | Non-radiated structures | |||||
Decommissioning | |||||
Total site study costs | 89 | ||||
GEORGIA POWER CO | Plant Vogtle | |||||
Decommissioning | |||||
Amount expensed for rate making purpose | $ 2 | ||||
GEORGIA POWER CO | Equity Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 415 | 326 | |||
GEORGIA POWER CO | Debt Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 502 | 477 | |||
GEORGIA POWER CO | Other Securities | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 12 | 11 | |||
GEORGIA POWER CO | Securities Investment | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Nuclear decommissioning trusts, at fair value | 568 | 803 | $ 980 | ||
GEORGIA POWER CO | Securities Held in Funds | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Increase (decrease) in fair value of securities related to nuclear decommissioning | 83 | $ 26 | |||
GEORGIA POWER CO | Unrealized Gain (Loss or Write-down) | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Increase (decrease) in fair value of securities related to nuclear decommissioning | (14) | ||||
Other regulatory assets current | GEORGIA POWER CO | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Environmental regulatory assets | 2 | 2 | |||
Other regulatory assets deferred | GEORGIA POWER CO | |||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Environmental regulatory assets | $ 47 | $ 33 |
Summary of Significant Accoun53
Summary of Significant Accounting Policies - AFUC and Interest Capitalized (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accounting Policies [Line Items] | ||||||
Allowance for equity funds used during construction | $ 160 | $ 202 | $ 226 | |||
AFUDC, net of income taxes | 25.50% | 11.40% | 12.80% | |||
Interest, net of amounts capitalized | $ 1,700 | $ 1,100 | $ 809 | |||
Net cash paid for capitalized interest | 89 | 125 | 124 | |||
ALABAMA POWER CO | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for equity funds used during construction | $ 39 | $ 28 | $ 60 | |||
Composite rate used for allowance for funds used during construction | 8.40% | 8.30% | 8.40% | 8.70% | ||
AFUDC, net of income taxes | 5.70% | 4.20% | 9.30% | |||
Interest, net of amounts capitalized | $ 285 | $ 277 | $ 250 | |||
Net cash paid for capitalized interest | $ 15 | $ 11 | 22 | |||
GEORGIA POWER CO | ||||||
Accounting Policies [Line Items] | ||||||
Composite rate used for allowance for funds used during construction | 6.90% | 5.60% | 6.90% | 6.50% | ||
Allowance for funds used during construction, capitalized interest | $ 63 | $ 68 | $ 56 | |||
AFUDC, net of income taxes | 3.80% | 4.60% | 3.90% | |||
Interest, net of amounts capitalized | $ 386 | $ 375 | $ 353 | |||
Net cash paid for capitalized interest | $ 23 | $ 20 | $ 16 | |||
GULF POWER CO | ||||||
Accounting Policies [Line Items] | ||||||
Composite rate used for allowance for funds used during construction | 5.73% | 5.73% | 5.73% | 5.73% | ||
AFUDC, net of income taxes | 0.07% | 0.00% | 10.80% | |||
Interest, net of amounts capitalized | $ 46 | $ 53 | $ 52 | |||
Net cash paid for capitalized interest | 0 | 0 | 6 | |||
MISSISSIPPI POWER CO | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for equity funds used during construction | $ 72 | $ 124 | $ 110 | |||
Composite rate used for allowance for funds used during construction | 6.50% | 6.70% | 6.50% | 5.99% | ||
Interest, net of amounts capitalized | $ 65 | $ 50 | $ 45 | |||
Net cash paid for capitalized interest | 29 | 49 | $ 66 | |||
SOUTHERN Co GAS | ||||||
Accounting Policies [Line Items] | ||||||
Interest, net of amounts capitalized | $ 135 | $ 223 | ||||
Atlanta Gas Light | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 4.05% | 8.10% | ||||
Chattanooga Gas | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 3.71% | 7.41% | ||||
Elizabethtown Gas | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 0.84% | 1.56% | ||||
Nicor Gas | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 1.50% | 1.22% | ||||
Predecessor | SOUTHERN Co GAS | ||||||
Accounting Policies [Line Items] | ||||||
Interest, net of amounts capitalized | $ 119 | $ 181 | ||||
Predecessor | Atlanta Gas Light | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 4.05% | 8.10% | ||||
Predecessor | Chattanooga Gas | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 3.71% | 7.41% | ||||
Predecessor | Elizabethtown Gas | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 0.84% | 1.69% | ||||
Predecessor | Nicor Gas | ||||||
Accounting Policies [Line Items] | ||||||
Allowance for funds under construction rate (as percent) | 1.50% | 0.82% |
Summary of Significant Accoun54
Summary of Significant Accounting Policies - Goodwill and Intangible Assets (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | |
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Asset Retirement Obligation, Cash Paid to Settle | $ 177 | $ 171 | $ 37 | |||
Goodwill | $ 6,251 | 6,268 | 6,251 | |||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 957 | 984 | 957 | |||
Accumulated Amortization | (62) | (186) | (62) | |||
Other Intangible Assets, Net | 895 | 798 | 895 | |||
Total other intangible assets, gross | 1,032 | 1,059 | 1,032 | |||
Total other intangible assets, net | 970 | 873 | 970 | |||
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract] | ||||||
2,018 | 95 | |||||
2,019 | 77 | |||||
2,020 | 65 | |||||
2,021 | 56 | |||||
2,022 | 51 | |||||
Amortization of intangible assets | 124 | 50 | $ 3 | |||
Customer relationships | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 268 | 288 | 268 | |||
Accumulated Amortization | (32) | (83) | (32) | |||
Other Intangible Assets, Net | 236 | 205 | 236 | |||
Trade names | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 158 | 159 | 158 | |||
Accumulated Amortization | (5) | (17) | (5) | |||
Other Intangible Assets, Net | 153 | 142 | 153 | |||
Storage and transportation contracts | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 64 | 64 | 64 | |||
Accumulated Amortization | (2) | (34) | (2) | |||
Other Intangible Assets, Net | 62 | 30 | 62 | |||
PPA fair value adjustments | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 456 | 456 | 456 | |||
Accumulated Amortization | (22) | (47) | (22) | |||
Other Intangible Assets, Net | 434 | 409 | 434 | |||
Other | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 11 | 17 | 11 | |||
Accumulated Amortization | (1) | (5) | (1) | |||
Other Intangible Assets, Net | 10 | $ 12 | $ 10 | |||
Minimum | Customer relationships | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 11 years | |||||
Minimum | Trade names | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 5 years | |||||
Minimum | Patents | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 3 years | |||||
Minimum | Storage and transportation contracts | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 1 year | |||||
Minimum | Software and other | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 1 year | |||||
Minimum | PPA fair value adjustments | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 10 years | |||||
Maximum | Customer relationships | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 26 years | |||||
Maximum | Trade names | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 28 years | |||||
Maximum | Patents | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 10 years | |||||
Maximum | Storage and transportation contracts | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 5 years | |||||
Maximum | Software and other | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 12 years | |||||
Maximum | PPA fair value adjustments | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 20 years | |||||
Utility Plant in Service | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.90% | 3.00% | 3.00% | |||
Parent Company | FCC Licenses | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Other intangible assets not subject to amortization: | 75 | $ 75 | $ 75 | |||
GEORGIA POWER CO | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Asset Retirement Obligation, Cash Paid to Settle | $ 120 | $ 123 | $ 29 | |||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.70% | 2.80% | 2.70% | |||
SOUTHERN Co GAS | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Goodwill | 5,967 | $ 5,967 | $ 5,967 | |||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 400 | 400 | 400 | |||
Accumulated Amortization | (34) | (120) | (34) | |||
Other Intangible Assets, Net | 366 | 280 | 366 | |||
Total other intangible assets, net | 366 | 280 | 366 | |||
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract] | ||||||
2,018 | 58 | |||||
2,019 | 40 | |||||
2,020 | 28 | |||||
2,021 | 21 | |||||
2,022 | 17 | |||||
Amortization of intangible assets | 32 | 54 | ||||
SOUTHERN Co GAS | Customer relationships | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 221 | 221 | 221 | |||
Accumulated Amortization | (30) | (77) | (30) | |||
Other Intangible Assets, Net | 191 | 144 | 191 | |||
SOUTHERN Co GAS | Trade names | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 115 | 115 | 115 | |||
Accumulated Amortization | (2) | (9) | (2) | |||
Other Intangible Assets, Net | 113 | 106 | 113 | |||
SOUTHERN Co GAS | Storage and transportation contracts | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Gross Carrying Amount | 64 | 64 | 64 | |||
Accumulated Amortization | (2) | (34) | (2) | |||
Other Intangible Assets, Net | 62 | $ 30 | $ 62 | |||
SOUTHERN Co GAS | Minimum | Customer relationships | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 11 years | |||||
SOUTHERN Co GAS | Minimum | Trade names | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 10 years | |||||
SOUTHERN Co GAS | Minimum | Storage and transportation contracts | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 1 year | |||||
SOUTHERN Co GAS | Maximum | Customer relationships | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 16 years | |||||
SOUTHERN Co GAS | Maximum | Trade names | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 28 years | |||||
SOUTHERN Co GAS | Maximum | Storage and transportation contracts | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 5 years | |||||
SOUTHERN Co GAS | Utility Plant in Service | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.90% | 2.80% | ||||
SOUTHERN Co GAS | Predecessor | ||||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Accumulated Amortization | (34) | $ (34) | ||||
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract] | ||||||
Amortization of intangible assets | $ 8 | $ 18 | ||||
SOUTHERN Co GAS | Predecessor | Minimum | Customer relationships | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 11 years | |||||
SOUTHERN Co GAS | Predecessor | Minimum | Trade names | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 10 years | |||||
SOUTHERN Co GAS | Predecessor | Maximum | Customer relationships | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 16 years | |||||
SOUTHERN Co GAS | Predecessor | Maximum | Trade names | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 28 years | |||||
SOUTHERN Co GAS | Predecessor | Utility Plant in Service | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.70% | |||||
SOUTHERN POWER CO | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Finite-lived intangible asset, useful life | 19 years | |||||
Finite-Lived Intangible Assets, Net [Abstract] | ||||||
Accumulated Amortization | (22) | $ (47) | $ (22) | |||
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract] | ||||||
2,018 | 25 | |||||
2,019 | 25 | |||||
2,020 | 25 | |||||
2,021 | 25 | |||||
2,022 | 25 | |||||
Amortization of intangible assets | 25 | 10 | $ 3 | |||
Gas Distribution Operations | SOUTHERN Co GAS | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Goodwill | 4,702 | 4,702 | 4,702 | |||
Gas Marketing Services | SOUTHERN Co GAS | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Goodwill | 1,265 | 1,265 | $ 1,265 | |||
Storage and Fuels Reporting Unit | SOUTHERN Co GAS | ||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ||||||
Goodwill | $ 14 | |||||
Wholesale Gas Services | SOUTHERN Co GAS | ||||||
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract] | ||||||
Amortization of intangible assets | $ 2 | $ 32 |
Summary of Significant Accoun55
Summary of Significant Accounting Policies - Intangible Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accounting Policies [Line Items] | ||
Other liabilities noncurrent | $ 691 | $ 880 |
SOUTHERN Co GAS | ||
Accounting Policies [Line Items] | ||
Intangible liabilities, accumulated amortization | 50 | |
Other liabilities noncurrent | 88 | $ 127 |
Finite-Lived Intangible Liabilities, Amortization Expense, Maturity Schedule [Abstract] | ||
2,018 | 24 | |
2,019 | 17 | |
Intangible Liabilities | SOUTHERN Co GAS | ||
Accounting Policies [Line Items] | ||
Other liabilities noncurrent | $ 91 |
Summary of Significant Accoun56
Summary of Significant Accounting Policies - Reserves and Leveraged Leases (Details) | Apr. 04, 2017USD ($) | Apr. 01, 2017 | Dec. 31, 2017USD ($)kWh | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Feb. 03, 2017USD ($) | Aug. 29, 2016USD ($) | Feb. 29, 2016USD ($) | Dec. 31, 2014USD ($) |
Net Investments from Leveraged Lease | |||||||||
Investment in leveraged leases | $ 86,000,000 | ||||||||
Components of Income from Leveraged Lease | |||||||||
Other regulatory assets, current | 604,000,000 | $ 581,000,000 | |||||||
Other regulatory assets, deferred | 6,943,000,000 | 6,851,000,000 | |||||||
Domestic And International Leveraged Lease | |||||||||
Net Investments from Leveraged Lease | |||||||||
Net rentals receivable | 1,498,000,000 | 1,481,000,000 | |||||||
Unearned income | (723,000,000) | (707,000,000) | |||||||
Investment in leveraged leases | 775,000,000 | 774,000,000 | |||||||
Deferred taxes from leveraged leases | (252,000,000) | (309,000,000) | |||||||
Net investment in leveraged leases | 523,000,000 | 465,000,000 | |||||||
Components of Income from Leveraged Lease | |||||||||
Pretax leveraged lease income (loss) | 25,000,000 | 25,000,000 | $ 20,000,000 | ||||||
Net impact of Tax Reform Legislation | 48,000,000 | 0 | 0 | ||||||
Income tax expense | (9,000,000) | (9,000,000) | (7,000,000) | ||||||
Net leveraged lease income (loss) | $ 64,000,000 | 16,000,000 | 13,000,000 | ||||||
Maximum | |||||||||
Leveraged Lease [Line Items] | |||||||||
Leveraged lease agreement term | 45 years | ||||||||
GEORGIA POWER CO | |||||||||
Leveraged Lease [Line Items] | |||||||||
Accrual under alternate rate plan | $ 30,000,000 | ||||||||
Property Damage Reserve, Percentage of Balance | 0.75 | ||||||||
Components of Income from Leveraged Lease | |||||||||
Other regulatory assets, current | 205,000,000 | 193,000,000 | |||||||
Other regulatory assets, deferred | 2,932,000,000 | 2,774,000,000 | |||||||
GULF POWER CO | |||||||||
Leveraged Lease [Line Items] | |||||||||
Psc approved annual property damage reserve accrual | 3,500,000 | ||||||||
Threshold above which additional property damage reserves are authorized by PSC | 3,500,000 | ||||||||
Reserve Value to Resume Property Damage Reserve Accruals | 0 | ||||||||
Increase (decrease) in recoverable property damage costs | $ 31,000,000 | $ 3,500,000 | 3,500,000 | 3,500,000 | |||||
Recovery period for natural disaster reserve costs | 60 days | ||||||||
Cumulative costs limit under PSC order | $ 100,000,000 | ||||||||
Accrued Asset Recovery Damaged Property Costs, Storm Reserve | 40,000,000 | ||||||||
PSC approved annual uninsured injuries and damages accrual | 1,600,000 | ||||||||
Threshold above with additional uninsured injuries and damages accruals are authorized by PSC | 1,600,000 | ||||||||
Liability for claims and claims adjustment expense | 2,100,000 | 1,400,000 | |||||||
Estimated liabilities for outstanding claims | 0 | 0 | |||||||
Accrued reserves | 40,000,000 | 40,000,000 | |||||||
Components of Income from Leveraged Lease | |||||||||
Regulatory asset | $ 63,000,000 | ||||||||
Other regulatory assets, current | 56,000,000 | 44,000,000 | |||||||
Other regulatory assets, deferred | 502,000,000 | 512,000,000 | |||||||
GULF POWER CO | Maximum | |||||||||
Leveraged Lease [Line Items] | |||||||||
PSC approved target level for property damage reserve | 55,000,000 | ||||||||
Customer surcharge storm recovery costs | $ 4 | ||||||||
Customer surcharge storm recovery capacity | kWh | 1,000 | ||||||||
PSC approved annual uninsured injuries and damages accrual | $ 2,000,000 | ||||||||
GULF POWER CO | Minimum | |||||||||
Leveraged Lease [Line Items] | |||||||||
PSC approved target level for property damage reserve | 48,000,000 | ||||||||
MISSISSIPPI POWER CO | |||||||||
Leveraged Lease [Line Items] | |||||||||
Threshold above which actual damages are charged to the reserve | 50,000 | ||||||||
Psc approved annual property damage reserve accrual | $ 1,000,000 | $ 3,000,000 | |||||||
Components of Income from Leveraged Lease | |||||||||
Retail accrual per annual SRR rate | 3,000,000 | 4,000,000 | 3,000,000 | $ 3,000,000 | |||||
Wholesale accrual per annual SRR rate | 300,000 | 300,000 | $ 300,000 | ||||||
Other regulatory assets, current | 125,000,000 | 115,000,000 | |||||||
Other regulatory assets, deferred | 437,000,000 | 518,000,000 | |||||||
Traditional Operating Companies | |||||||||
Leveraged Lease [Line Items] | |||||||||
Accrued reserves | $ 41,000,000 | 40,000,000 | $ 40,000,000 | ||||||
Mississippi Public Service Commission | MISSISSIPPI POWER CO | |||||||||
Components of Income from Leveraged Lease | |||||||||
Period to agree on system restoration rider | 3 years | ||||||||
Retail | |||||||||
Components of Income from Leveraged Lease | |||||||||
Proposed property damage reserve | $ 56,000,000 | ||||||||
Wholesale | |||||||||
Components of Income from Leveraged Lease | |||||||||
Proposed property damage reserve | 1,000,000 | ||||||||
Property damage reserves-liability | GEORGIA POWER CO | |||||||||
Components of Income from Leveraged Lease | |||||||||
Regulatory asset | 333,000,000 | 206,000,000 | |||||||
Other regulatory assets, current | 30,000,000 | 30,000,000 | |||||||
Other regulatory assets, deferred | 303,000,000 | 176,000,000 | |||||||
Other current liabilities | GULF POWER CO | |||||||||
Leveraged Lease [Line Items] | |||||||||
Liability for claims and claims adjustment expense | 1,600,000 | $ 1,400,000 | |||||||
Other deferred credits and liabilities | GULF POWER CO | |||||||||
Leveraged Lease [Line Items] | |||||||||
Liability for claims and claims adjustment expense | $ 500,000 |
Summary of Significant Accoun57
Summary of Significant Accounting Policies - Environmental Recovery (Details) - GEORGIA POWER CO - USD ($) $ in Millions | 1 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accounting Policies [Line Items] | |||
Environmental exit costs, assets previously disposed, liability for remediation | $ 22 | $ 17 | |
Environmental regulatory assets | 49 | 35 | |
Environmental Remediation Reserve | |||
Accounting Policies [Line Items] | |||
Costs recovered annually under rate plan | $ 2 | ||
Other regulatory assets current | |||
Accounting Policies [Line Items] | |||
Environmental regulatory assets | 2 | 2 | |
Other regulatory assets deferred | |||
Accounting Policies [Line Items] | |||
Environmental regulatory assets | $ 47 | $ 33 |
Summary of Significant Accoun58
Summary of Significant Accounting Policies - Transmission Receivables/Payables, Cash and Accumulated OCI (loss) (Details) $ in Millions | 6 Months Ended | 12 Months Ended | |||||
Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)counterpartycustomer | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2014USD ($) | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Required collateral credit rating downgrade | $ 0 | $ 8 | $ 0 | ||||
Stockholders' equity | 26,612 | $ 25,528 | 26,612 | $ 21,982 | $ 8,001 | $ 20,926 | |
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ (180) | ||||||
Current period change | (9) | (50) | (2) | ||||
Ending Balance | (180) | (189) | (180) | ||||
Other comprehensive income (loss) | (9) | (50) | (2) | ||||
Qualifying Hedges | |||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | (115) | ||||||
Current period change | (4) | ||||||
Ending Balance | (115) | (119) | (115) | ||||
Pension and Other Postretirement Benefit Plans | |||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | (65) | ||||||
Current period change | (5) | ||||||
Ending Balance | (65) | (70) | (65) | ||||
Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | (180) | (189) | (180) | (130) | (128) | ||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | (9) | (50) | (2) | ||||
ALABAMA POWER CO | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 6,323 | $ 6,829 | 6,323 | 5,992 | 5,752 | ||
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ (30) | ||||||
Current period change | 4 | 2 | (3) | ||||
Ending Balance | (30) | (26) | (30) | ||||
Other comprehensive income (loss) | 4 | 2 | (3) | ||||
ALABAMA POWER CO | Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | (30) | (26) | (30) | (32) | (29) | ||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | 4 | 2 | (3) | ||||
GEORGIA POWER CO | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 11,356 | $ 11,931 | 11,356 | 10,719 | 10,421 | ||
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ (13) | ||||||
Current period change | 3 | 2 | (7) | ||||
Ending Balance | (13) | (10) | (13) | ||||
Other comprehensive income (loss) | 3 | 2 | (7) | ||||
GEORGIA POWER CO | Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | (13) | (10) | (13) | (15) | (8) | ||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | 3 | 2 | (7) | ||||
GULF POWER CO | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 1,389 | $ 1,531 | 1,389 | 1,355 | 1,309 | ||
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ 1 | ||||||
Current period change | (1) | 1 | 1 | ||||
Ending Balance | 1 | 0 | 1 | ||||
Other comprehensive income (loss) | (1) | 1 | 1 | ||||
GULF POWER CO | Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 1 | 0 | 1 | 0 | (1) | ||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | (1) | 1 | 1 | ||||
MISSISSIPPI POWER CO | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 2,943 | $ 1,358 | 2,943 | 2,359 | 2,084 | ||
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ (4) | ||||||
Current period change | 2 | 1 | |||||
Ending Balance | (4) | (4) | (4) | ||||
Other comprehensive income (loss) | 0 | 2 | 1 | ||||
MISSISSIPPI POWER CO | Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | (4) | (4) | (4) | (6) | (7) | ||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | 2 | 1 | |||||
SOUTHERN POWER CO | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 5,675 | $ 6,498 | 5,675 | 3,264 | 1,971 | ||
Period of reimbursement of transmission costs | 5 years | ||||||
Restricted cash and cash equivalents noncurrent | 13 | $ 11 | 13 | ||||
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ 35 | ||||||
Current period change | (10) | 31 | 1 | ||||
Other Comprehensive Income (Loss), Transfer from Service Company | [1] | 27 | |||||
Ending Balance | 35 | (2) | 35 | ||||
Other comprehensive income (loss) | (10) | 31 | 1 | ||||
SOUTHERN POWER CO | Qualifying Hedges | |||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | 35 | ||||||
Current period change | (10) | ||||||
Other Comprehensive Income (Loss), Transfer from Service Company | 0 | ||||||
Ending Balance | 35 | 25 | 35 | ||||
SOUTHERN POWER CO | Pension and Other Postretirement Benefit Plans | |||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | 0 | ||||||
Current period change | 0 | ||||||
Other Comprehensive Income (Loss), Transfer from Service Company | 27 | ||||||
Ending Balance | 0 | (27) | 0 | ||||
Other comprehensive income (loss) | 27 | ||||||
Other Comprehensive Income (Loss), Transfer from Service Company, Net of Tax | 9 | ||||||
SOUTHERN POWER CO | Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 35 | (2) | 35 | 4 | $ 3 | ||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | (10) | 31 | $ 1 | ||||
Other Comprehensive Income (Loss), Transfer from Service Company | [1] | 27 | |||||
SOUTHERN Co GAS | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 9,109 | $ 9,022 | 9,109 | ||||
Original maturities of temporary cash investments | 90 days | ||||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Beginning Balance | $ 26 | ||||||
Current period change | 26 | (5) | |||||
Ending Balance | 26 | 20 | 26 | ||||
Other comprehensive income (loss) | 26 | (5) | |||||
SOUTHERN Co GAS | Accumulated Other Comprehensive Income (Loss) | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Stockholders' equity | 26 | 20 | $ 26 | ||||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||||||
Current period change | $ 26 | $ (5) | |||||
Atlanta Gas Light | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Concentration risk, number of customers | customer | 15 | ||||||
Wholesale Gas Services | Accounts Receivable | Credit Concentration Risk | SOUTHERN Co GAS | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Number of top counterparties | counterparty | 20 | ||||||
Wholesale Services | Accounts Receivable | Credit Concentration Risk | SOUTHERN Co GAS | |||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||
Concentration risk (as percent) | 48.00% | ||||||
Accounts receivable | $ 203 | ||||||
[1] | Amount includes carry-over OCI balance of $27 million in connection with the Company becoming a participant to the Southern Company qualified pension plan. |
Summary of Significant Accoun59
Summary of Significant Accounting Policies - Financial Instruments and Inventory at Lower of Cost or Market Adjustment (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2015 |
Inventory [Line Items] | ||||
Derivative collateral obligation to return cash | $ 0 | |||
ALABAMA POWER CO | ||||
Inventory [Line Items] | ||||
Derivative collateral obligation to return cash | 0 | |||
GULF POWER CO | ||||
Inventory [Line Items] | ||||
Derivative collateral obligation to return cash | 0 | |||
SOUTHERN POWER CO | ||||
Inventory [Line Items] | ||||
Derivative collateral obligation to return cash | 0 | $ 0 | ||
SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | 2,000,000 | 1,000,000 | ||
Derivative collateral obligation to return cash | 0 | |||
Nicor Gas | ||||
Inventory [Line Items] | ||||
Inventory net | 264,000,000 | |||
LIFO inventory amount | 148,000,000 | |||
Gas Marketing Services | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | 0 | 0 | ||
Wholesale Gas Services | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | 2,000,000 | 1,000,000 | ||
All Other | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | $ 0 | $ 0 | ||
Predecessor | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | $ 3,000,000 | $ 23,000,000 | ||
Predecessor | Gas Marketing Services | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | 0 | 3,000,000 | ||
Predecessor | Wholesale Gas Services | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | 3,000,000 | 19,000,000 | ||
Predecessor | All Other | SOUTHERN Co GAS | ||||
Inventory [Line Items] | ||||
Inventory valuation reserves | $ 0 | $ 1,000,000 |
Summary of Significant Accoun60
Summary of Significant Accounting Policies - Variable Interest Entity (Details) - MISSISSIPPI POWER CO - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Variable Interest Entity [Line Items] | ||
VIE, assets carrying amount | $ 20 | |
VIE, liabilities carrying amount | $ 38 | $ 24 |
Retirement Benefits - Actuarial
Retirement Benefits - Actuarial Assumptions (Details) | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.92% | 8.16% | 8.20% | ||
Annual salary increase on net periodic benefit costs | 4.37% | 4.37% | 3.59% | ||
Discount rate, benefit obligation | 4.40% | 3.80% | 4.40% | ||
Annual salary increase, benefit obligation | 4.37% | 4.32% | 4.37% | ||
Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 6.84% | 6.66% | 6.97% | ||
Annual salary increase on net periodic benefit costs | 4.37% | 4.37% | 3.59% | ||
Discount rate, benefit obligation | 4.23% | 3.68% | 4.23% | ||
Annual salary increase, benefit obligation | 4.37% | 4.32% | 4.37% | ||
Employee benefit obligations | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.40% | 4.58% | 4.17% | ||
Employee benefit obligations | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.23% | 4.38% | 4.04% | ||
Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.77% | 3.88% | 4.17% | ||
Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.54% | 3.66% | 4.04% | ||
Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.81% | 4.98% | 4.48% | ||
Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.64% | 4.85% | 4.39% | ||
MISSISSIPPI POWER CO | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.95% | 8.20% | 8.20% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.44% | 3.80% | 4.44% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 6.88% | 7.07% | 7.23% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.22% | 3.68% | 4.22% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
MISSISSIPPI POWER CO | Employee benefit obligations | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.44% | 4.69% | 4.17% | ||
MISSISSIPPI POWER CO | Employee benefit obligations | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.22% | 4.47% | 4.03% | ||
MISSISSIPPI POWER CO | Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.81% | 3.97% | 4.17% | ||
MISSISSIPPI POWER CO | Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.55% | 3.66% | 4.03% | ||
MISSISSIPPI POWER CO | Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.83% | 5.04% | 4.49% | ||
MISSISSIPPI POWER CO | Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.65% | 4.88% | 4.38% | ||
ALABAMA POWER CO | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.95% | 8.20% | 8.20% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.44% | 3.81% | 4.44% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
ALABAMA POWER CO | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 6.83% | 6.83% | 7.17% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.27% | 3.71% | 4.27% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
ALABAMA POWER CO | Employee benefit obligations | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.44% | 4.67% | 4.18% | ||
ALABAMA POWER CO | Employee benefit obligations | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.27% | 4.51% | 4.04% | ||
ALABAMA POWER CO | Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.76% | 3.90% | 4.18% | ||
ALABAMA POWER CO | Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.58% | 3.69% | 4.04% | ||
ALABAMA POWER CO | Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.85% | 5.07% | 4.49% | ||
ALABAMA POWER CO | Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.70% | 4.96% | 4.40% | ||
GEORGIA POWER CO | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.95% | 8.20% | 8.20% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.40% | 3.79% | 4.40% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
GEORGIA POWER CO | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 6.79% | 6.27% | 6.48% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.23% | 3.68% | 4.23% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
GEORGIA POWER CO | Employee benefit obligations | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.40% | 4.65% | 4.18% | ||
GEORGIA POWER CO | Employee benefit obligations | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.23% | 4.49% | 4.03% | ||
GEORGIA POWER CO | Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.72% | 3.86% | 4.18% | ||
GEORGIA POWER CO | Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.55% | 3.67% | 4.03% | ||
GEORGIA POWER CO | Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.83% | 5.03% | 4.49% | ||
GEORGIA POWER CO | Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.63% | 4.88% | 4.39% | ||
GULF POWER CO | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.95% | 8.20% | 8.20% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.46% | 3.82% | 4.46% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
GULF POWER CO | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.81% | 8.05% | 8.07% | ||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||
Discount rate, benefit obligation | 4.25% | 3.69% | 4.25% | ||
Annual salary increase, benefit obligation | 4.46% | 4.46% | 4.46% | ||
GULF POWER CO | Employee benefit obligations | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.18% | ||||
GULF POWER CO | Employee benefit obligations | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.46% | 4.71% | |||
GULF POWER CO | Employee benefit obligations | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.25% | 4.51% | 4.04% | ||
GULF POWER CO | Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.82% | 3.97% | 4.18% | ||
GULF POWER CO | Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.56% | 3.68% | 4.04% | ||
GULF POWER CO | Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.81% | 5.04% | 4.48% | ||
GULF POWER CO | Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.62% | 4.88% | 4.38% | ||
SOUTHERN POWER CO | Employee benefit obligations | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.94% | ||||
Annual salary increase on net periodic benefit costs | 4.46% | ||||
SOUTHERN POWER CO | Employee benefit obligations | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.81% | ||||
Annual salary increase on net periodic benefit costs | 4.46% | ||||
SOUTHERN Co GAS | |||||
Pension Plans and Postretirement Plans | |||||
Pension band increase, benefit obligation | 2.00% | 2.00% | 2.00% | ||
SOUTHERN Co GAS | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.75% | 7.60% | |||
Annual salary increase on net periodic benefit costs | 3.50% | 3.50% | |||
Pension bad increase on net periodic benefit costs | 2.00% | ||||
Discount rate, benefit obligation | 4.39% | 3.74% | 4.39% | ||
Annual salary increase, benefit obligation | 3.50% | 2.88% | 3.50% | ||
Pension band increase, benefit obligation | 2.00% | 2.00% | |||
SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 5.93% | 6.03% | |||
Annual salary increase on net periodic benefit costs | 3.50% | 3.50% | |||
Discount rate, benefit obligation | 4.15% | 3.62% | 4.15% | ||
Annual salary increase, benefit obligation | 3.50% | 2.56% | 3.50% | ||
SOUTHERN Co GAS | Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.21% | 3.76% | |||
SOUTHERN Co GAS | Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 2.84% | 3.40% | |||
SOUTHERN Co GAS | Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.07% | 4.64% | |||
SOUTHERN Co GAS | Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.96% | 4.55% | |||
SOUTHERN Co GAS | Predecessor | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 7.80% | 7.80% | |||
Annual salary increase on net periodic benefit costs | 3.70% | 3.70% | |||
Pension bad increase on net periodic benefit costs | 2.00% | 2.00% | |||
SOUTHERN Co GAS | Predecessor | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Long-term return on plan assets on net periodic benefit costs | 6.60% | 7.80% | |||
Annual salary increase on net periodic benefit costs | 3.70% | 3.70% | |||
SOUTHERN Co GAS | Predecessor | Interest costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.00% | 4.20% | |||
SOUTHERN Co GAS | Predecessor | Interest costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 3.60% | 4.00% | |||
SOUTHERN Co GAS | Predecessor | Service costs | Pension plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.80% | 4.20% | |||
SOUTHERN Co GAS | Predecessor | Service costs | Other postretirement benefit plans | |||||
Pension Plans and Postretirement Plans | |||||
Discount rate on net periodic benefit costs | 4.70% | 4.00% |
Retirement Benefits - Textual (
Retirement Benefits - Textual (Details) | Jan. 01, 2018 | Dec. 19, 2016USD ($) | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($)Employee | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Aug. 29, 2016USD ($) |
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | ||||||||
Total accumulated benefit obligation for the pension plans | $ (11,300,000,000) | $ (12,600,000,000) | $ (11,300,000,000) | ||||||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||||||||
Actual plan asset allocations (as percent) | 100.00% | ||||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Defined contribution plan, cost | $ 118,000,000 | 105,000,000 | $ 92,000,000 | ||||||
Defined contribution plan, employer discretionary contribution amount | 0 | $ 2,000,000 | 2,000,000 | 2,000,000 | |||||
Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | 13,200,000,000 | ||||||||
Non Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 652,000,000 | ||||||||
Southern Company Services, Inc. | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Number of employee transfers | Employee | 538 | ||||||||
GEORGIA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Expected postretirement trust contributions | $ 0 | ||||||||
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 CO | Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 4,000,000,000 | ||||||||
GEORGIA POWER CO | Non Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 153,000,000 | ||||||||
GEORGIA POWER CO | Employee Savings Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 6.00% | ||||||||
GEORGIA POWER CO | Maximum | Employee Savings Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Maximum limit of contribution of employees base salary | 5.10% | ||||||||
SOUTHERN Co GAS | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Total accumulated benefit obligation for the pension plans | (1,100,000,000) | $ (1,100,000,000) | (1,100,000,000) | ||||||
SOUTHERN Co GAS | Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | 1,100,000,000 | ||||||||
SOUTHERN Co GAS | Non Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 44,000,000 | ||||||||
SOUTHERN Co GAS | Employee Savings Plan Option One Contribution Percentage | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 65.00% | ||||||||
SOUTHERN Co GAS | Employee Savings Plan First Matching Contribution Percentage | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 100.00% | ||||||||
SOUTHERN Co GAS | Employee Saving Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 75.00% | ||||||||
SOUTHERN Co GAS | Pension and Other Postretirement Plans Costs | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Regulatory asset | $ 437,000,000 | ||||||||
SOUTHERN Co GAS | Maximum | Employee Savings Plan Option One Contribution Percentage | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Maximum limit of contribution of employees base salary | 8.00% | ||||||||
SOUTHERN Co GAS | Maximum | Employee Savings Plan First Matching Contribution Percentage | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Maximum limit of contribution of employees base salary | 3.00% | ||||||||
SOUTHERN Co GAS | Maximum | Employee Saving Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Maximum limit of contribution of employees base salary | 3.00% | ||||||||
ALABAMA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Expected postretirement trust contributions | $ 0 | ||||||||
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) | $ (2,700,000,000) | (2,400,000,000) | ||||||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||||||||
Defined contribution plan, cost | $ 23,000,000 | 23,000,000 | 22,000,000 | ||||||
ALABAMA POWER CO | Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | 2,900,000,000 | ||||||||
ALABAMA POWER CO | Non Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 126,000,000 | ||||||||
ALABAMA POWER CO | Employee Savings Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 6.00% | ||||||||
Maximum limit of contribution of employees base salary | 5.10% | ||||||||
GULF POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
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 | ||||||||
Regulatory asset | $ 63,000,000 | ||||||||
GULF POWER CO | Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Expected postretirement trust contributions | $ 0 | ||||||||
Projected benefit obligations | 563,000,000 | ||||||||
GULF POWER CO | Non Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 25,000,000 | ||||||||
GULF POWER CO | Employee Savings Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 6.00% | ||||||||
Maximum limit of contribution of employees base salary | 5.10% | ||||||||
MISSISSIPPI POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | ||||||||
Total accumulated benefit obligation for the pension plans | $ (479,000,000) | $ (541,000,000) | $ (479,000,000) | ||||||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||||||||
MISSISSIPPI POWER CO | Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Expected postretirement trust contributions | $ 0 | ||||||||
Projected benefit obligations | 571,000,000 | ||||||||
MISSISSIPPI POWER CO | Non Qualified Pension Plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Projected benefit obligations | $ 31,000,000 | ||||||||
MISSISSIPPI POWER CO | Employee Savings Plan | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Matching limit of contribution by employer | 6.00% | ||||||||
Maximum limit of contribution of employees base salary | 5.10% | ||||||||
SOUTHERN POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | $ 36,000,000 | ||||||||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 20.00% | 19.00% | 20.00% | ||||||
Target plan asset allocations (as percent) | 15.00% | ||||||||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Other Types Of Investments | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 10.00% | 10.00% | 10.00% | ||||||
Target plan asset allocations (as percent) | 30.00% | ||||||||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Equity Securities | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 69.00% | 65.00% | 69.00% | ||||||
Target plan asset allocations (as percent) | 53.00% | ||||||||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Cash and Cash Equivalents | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 1.00% | 6.00% | 1.00% | ||||||
Target plan asset allocations (as percent) | 2.00% | ||||||||
Employee Savings Plan | GEORGIA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined contribution plan, cost | $ 26,000,000 | $ 27,000,000 | 26,000,000 | ||||||
Employee Savings Plan | SOUTHERN Co GAS | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined contribution plan, cost | 17,000,000 | 8,000,000 | |||||||
Employee Savings Plan | SOUTHERN Co GAS | Predecessor | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined contribution plan, cost | 10,000,000 | 16,000,000 | |||||||
Employee Savings Plan | GULF POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined contribution plan, cost | 5,000,000 | 5,000,000 | 4,000,000 | ||||||
Employee Savings Plan | MISSISSIPPI POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined contribution plan, cost | 5,000,000 | 5,000,000 | 5,000,000 | ||||||
Pension plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 637,000,000 | ||||||||
Benefit Payments, 2018 | 634,000,000 | ||||||||
Employer contributions | 52,000,000 | 1,076,000,000 | |||||||
Defined benefit plan, AOCI, gain (loss), before tax | $ (3,165,000,000) | (3,244,000,000) | (3,165,000,000) | ||||||
Projected benefit obligations | $ 12,385,000,000 | $ 13,808,000,000 | $ 12,385,000,000 | $ 10,542,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.37% | 4.37% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | |||||||
Target plan asset allocations (as percent) | 100.00% | 100.00% | |||||||
Benefit Payments, 2020 | $ 663,000,000 | ||||||||
Benefit Payments, 2021 | 681,000,000 | ||||||||
Benefit Payments, 2022 | 704,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 3,836,000,000 | ||||||||
Pension plans | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||||||
Target plan asset allocations (as percent) | 23.00% | 23.00% | 23.00% | ||||||
Pension plans | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 3,120,000,000 | $ 3,155,000,000 | $ 3,120,000,000 | $ 2,998,000,000 | |||||
Defined benefit plan, AOCI, gain (loss), before tax | (3,069,000,000) | (3,140,000,000) | (3,069,000,000) | ||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 155,000,000 | 145,000,000 | |||||||
Pension plans | GEORGIA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 201,000,000 | ||||||||
Benefit Payments, 2018 | 196,000,000 | ||||||||
Employer contributions | $ 0 | 14,000,000 | 301,000,000 | ||||||
Defined benefit plan, AOCI, gain (loss), before tax | (1,112,000,000) | (1,091,000,000) | (1,112,000,000) | ||||||
Expected postretirement trust contributions | 0 | ||||||||
Total accumulated benefit obligation for the pension plans | (3,500,000,000) | (3,800,000,000) | (3,500,000,000) | ||||||
Projected benefit obligations | $ 3,800,000,000 | $ 4,188,000,000 | $ 3,800,000,000 | $ 3,615,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 207,000,000 | ||||||||
Benefit Payments, 2021 | 210,000,000 | ||||||||
Benefit Payments, 2022 | 216,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 1,156,000,000 | ||||||||
Pension plans | GEORGIA POWER CO | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||||||
Target plan asset allocations (as percent) | 23.00% | ||||||||
Pension plans | GEORGIA POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 1,129,000,000 | $ 1,105,000,000 | $ 1,129,000,000 | $ 1,076,000,000 | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 57,000,000 | 55,000,000 | |||||||
Pension plans | SOUTHERN Co GAS | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 77,000,000 | ||||||||
Benefit Payments, 2018 | 100,000,000 | ||||||||
Employer contributions | 129,000,000 | 1,000,000 | |||||||
Defined benefit plan, AOCI, gain (loss), before tax | (226,000,000) | (155,000,000) | (226,000,000) | ||||||
Projected benefit obligations | $ 1,133,000,000 | 1,244,000,000 | $ 1,184,000,000 | 1,133,000,000 | |||||
Annual salary increase on net periodic benefit costs | 3.50% | 3.50% | |||||||
Regulatory asset | 334,000,000 | ||||||||
Defined benefit plan, benefit obligation, period increase (decrease) | 177,000,000 | ||||||||
Defined benefit plan, plan assets, period increase (decrease) | (10,000,000) | ||||||||
Benefit Payments, 2020 | $ 79,000,000 | ||||||||
Benefit Payments, 2021 | 79,000,000 | ||||||||
Benefit Payments, 2022 | 80,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | 392,000,000 | ||||||||
Defined Benefit Plan, Amortization of Gain (Loss) | $ (14,000,000) | (18,000,000) | |||||||
Pension plans | SOUTHERN Co GAS | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | 267,000,000 | 368,000,000 | 217,000,000 | 267,000,000 | |||||
Defined benefit plan, AOCI, gain (loss), before tax | (269,000,000) | (197,000,000) | (269,000,000) | ||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 15,000,000 | 18,000,000 | |||||||
Pension plans | SOUTHERN Co GAS | Predecessor | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Employer contributions | 1,000,000 | ||||||||
Projected benefit obligations | $ 1,244,000,000 | $ 1,067,000,000 | |||||||
Annual salary increase on net periodic benefit costs | 3.70% | 3.70% | |||||||
Defined Benefit Plan, Amortization of Gain (Loss) | $ (13,000,000) | $ (31,000,000) | |||||||
Pension plans | SOUTHERN Co GAS | Predecessor | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | 84,000,000 | 88,000,000 | |||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 4,000,000 | ||||||||
Pension plans | ALABAMA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 134,000,000 | ||||||||
Benefit Payments, 2018 | 129,000,000 | ||||||||
Employer contributions | 0 | 12,000,000 | 141,000,000 | ||||||
Expected postretirement trust contributions | 0 | ||||||||
Projected benefit obligations | $ 2,663,000,000 | $ 2,998,000,000 | $ 2,663,000,000 | $ 2,506,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 139,000,000 | ||||||||
Benefit Payments, 2021 | 143,000,000 | ||||||||
Benefit Payments, 2022 | 148,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 807,000,000 | ||||||||
Pension plans | ALABAMA POWER CO | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||||||
Target plan asset allocations (as percent) | 23.00% | ||||||||
Pension plans | ALABAMA POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 870,000,000 | $ 890,000,000 | $ 870,000,000 | $ 822,000,000 | |||||
Defined benefit plan, AOCI, gain (loss), before tax | (860,000,000) | (882,000,000) | (860,000,000) | ||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 42,000,000 | 40,000,000 | |||||||
Pension plans | GULF POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 23,000,000 | ||||||||
Benefit Payments, 2018 | 22,000,000 | ||||||||
Employer contributions | 0 | 1,000,000 | 49,000,000 | ||||||
Defined benefit plan, AOCI, gain (loss), before tax | (150,000,000) | (158,000,000) | (150,000,000) | ||||||
Total accumulated benefit obligation for the pension plans | (460,000,000) | (524,000,000) | (460,000,000) | ||||||
Projected benefit obligations | $ 517,000,000 | $ 587,000,000 | $ 517,000,000 | $ 480,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 25,000,000 | ||||||||
Benefit Payments, 2021 | 26,000,000 | ||||||||
Benefit Payments, 2022 | 28,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 155,000,000 | ||||||||
Pension plans | GULF POWER CO | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||||||
Target plan asset allocations (as percent) | 23.00% | ||||||||
Pension plans | GULF POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 153,000,000 | $ 160,000,000 | $ 153,000,000 | $ 142,000,000 | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 7,000,000 | 6,000,000 | |||||||
Pension plans | MISSISSIPPI POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 24,000,000 | ||||||||
Benefit Payments, 2018 | 23,000,000 | ||||||||
Employer contributions | $ 0 | 2,000,000 | 50,000,000 | ||||||
Defined benefit plan, AOCI, gain (loss), before tax | (151,000,000) | (155,000,000) | (151,000,000) | ||||||
Projected benefit obligations | $ 534,000,000 | $ 602,000,000 | $ 534,000,000 | $ 500,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 26,000,000 | ||||||||
Benefit Payments, 2021 | 27,000,000 | ||||||||
Benefit Payments, 2022 | 28,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 164,000,000 | ||||||||
Pension plans | MISSISSIPPI POWER CO | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||||||
Target plan asset allocations (as percent) | 23.00% | ||||||||
Pension plans | MISSISSIPPI POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 154,000,000 | $ 158,000,000 | $ 154,000,000 | $ 144,000,000 | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 7,000,000 | 7,000,000 | |||||||
Pension plans | SOUTHERN POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined benefit plan, AOCI, gain (loss), before tax | (32,000,000) | ||||||||
Total accumulated benefit obligation for the pension plans | (111,000,000) | ||||||||
Projected benefit obligations | $ 139,000,000 | ||||||||
Actual plan asset allocations (as percent) | 100.00% | ||||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Assets for Plan Benefits, Defined Benefit Plan | $ 138,000,000 | ||||||||
Pension plans | SOUTHERN POWER CO | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 24.00% | ||||||||
Target plan asset allocations (as percent) | 23.00% | ||||||||
Other postretirement benefit plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | $ 148,000,000 | ||||||||
Benefit Payments, 2018 | 144,000,000 | ||||||||
Employer contributions | 84,000,000 | 65,000,000 | |||||||
Defined benefit plan, AOCI, gain (loss), before tax | (360,000,000) | (324,000,000) | (360,000,000) | ||||||
Expected postretirement trust contributions | 0 | ||||||||
Projected benefit obligations | $ 2,297,000,000 | $ 2,339,000,000 | $ 2,297,000,000 | $ 1,989,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.37% | 4.37% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Benefit Payments, 2020 | $ 151,000,000 | ||||||||
Benefit Payments, 2021 | 154,000,000 | ||||||||
Benefit Payments, 2022 | 156,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 780,000,000 | ||||||||
Other postretirement benefit plans | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | 31.00% | ||||||
Target plan asset allocations (as percent) | 29.00% | 30.00% | 29.00% | ||||||
Other postretirement benefit plans | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 378,000,000 | $ 341,000,000 | $ 378,000,000 | $ 411,000,000 | |||||
Defined benefit plan, AOCI, gain (loss), before tax | (353,000,000) | (320,000,000) | (353,000,000) | ||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 13,000,000 | 14,000,000 | |||||||
Other postretirement benefit plans | GEORGIA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 55,000,000 | ||||||||
Benefit Payments, 2018 | 55,000,000 | ||||||||
Employer contributions | 26,000,000 | 17,000,000 | |||||||
Defined benefit plan, AOCI, gain (loss), before tax | (207,000,000) | (197,000,000) | (207,000,000) | ||||||
Projected benefit obligations | $ 847,000,000 | $ 863,000,000 | $ 847,000,000 | $ 854,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 56,000,000 | ||||||||
Benefit Payments, 2021 | 57,000,000 | ||||||||
Benefit Payments, 2022 | 58,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | 288,000,000 | ||||||||
Other postretirement benefit plans | GEORGIA POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 213,000,000 | 202,000,000 | $ 213,000,000 | $ 223,000,000 | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 8,000,000 | 9,000,000 | |||||||
Other postretirement benefit plans | SOUTHERN Co GAS | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 20,000,000 | ||||||||
Benefit Payments, 2018 | 20,000,000 | ||||||||
Employer contributions | 11,000,000 | 17,000,000 | |||||||
Defined benefit plan, AOCI, gain (loss), before tax | 61,000,000 | 44,000,000 | 61,000,000 | ||||||
Expected postretirement trust contributions | 0 | ||||||||
Projected benefit obligations | $ 308,000,000 | 338,000,000 | $ 310,000,000 | $ 308,000,000 | |||||
Annual salary increase on net periodic benefit costs | 3.50% | 3.50% | |||||||
Regulatory asset | 77,000,000 | ||||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Defined benefit plan, benefit obligation, period increase (decrease) | 20,000,000 | ||||||||
Defined benefit plan, plan assets, period increase (decrease) | $ 1,000,000 | ||||||||
Benefit Payments, 2020 | $ 21,000,000 | ||||||||
Benefit Payments, 2021 | 21,000,000 | ||||||||
Benefit Payments, 2022 | 22,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | 105,000,000 | ||||||||
Defined Benefit Plan, Amortization of Gain (Loss) | $ 0 | $ (4,000,000) | |||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 23.00% | 20.00% | 23.00% | ||||||
Target plan asset allocations (as percent) | 24.00% | ||||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Other Types Of Investments | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | 2.00% | ||||||
Target plan asset allocations (as percent) | 3.00% | ||||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Equity Securities | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 74.00% | 76.00% | 74.00% | ||||||
Target plan asset allocations (as percent) | 72.00% | ||||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Cash and Cash Equivalents | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | 1.00% | ||||||
Target plan asset allocations (as percent) | 1.00% | ||||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 52,000,000 | 77,000,000 | $ 46,000,000 | $ 52,000,000 | |||||
Defined benefit plan, AOCI, gain (loss), before tax | 64,000,000 | 47,000,000 | 64,000,000 | ||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 3,000,000 | 4,000,000 | |||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Predecessor | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Employer contributions | 10,000,000 | ||||||||
Projected benefit obligations | 318,000,000 | $ 338,000,000 | 318,000,000 | ||||||
Annual salary increase on net periodic benefit costs | 3.70% | 3.70% | |||||||
Defined Benefit Plan, Amortization of Gain (Loss) | $ (2,000,000) | $ (6,000,000) | |||||||
Other postretirement benefit plans | SOUTHERN Co GAS | Predecessor | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | 30,000,000 | 30,000,000 | |||||||
Defined Benefit Plan, Amortization of Gain (Loss) | $ 1,000,000 | ||||||||
Other postretirement benefit plans | ALABAMA POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 32,000,000 | ||||||||
Benefit Payments, 2018 | 31,000,000 | ||||||||
Employer contributions | 6,000,000 | 7,000,000 | |||||||
Projected benefit obligations | $ 501,000,000 | $ 517,000,000 | $ 501,000,000 | $ 505,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 33,000,000 | ||||||||
Benefit Payments, 2021 | 34,000,000 | ||||||||
Benefit Payments, 2022 | 35,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | 173,000,000 | ||||||||
Other postretirement benefit plans | ALABAMA POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 76,000,000 | 56,000,000 | $ 76,000,000 | $ 82,000,000 | |||||
Defined benefit plan, AOCI, gain (loss), before tax | (61,000,000) | (45,000,000) | (61,000,000) | ||||||
Defined Benefit Plan, Amortization of Gain (Loss) | 1,000,000 | 2,000,000 | |||||||
Other postretirement benefit plans | GULF POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 5,000,000 | ||||||||
Benefit Payments, 2018 | 5,000,000 | ||||||||
Employer contributions | 4,000,000 | 3,000,000 | |||||||
Defined benefit plan, AOCI, gain (loss), before tax | 7,000,000 | 6,000,000 | 7,000,000 | ||||||
Expected postretirement trust contributions | 0 | ||||||||
Projected benefit obligations | $ 83,000,000 | $ 83,000,000 | $ 83,000,000 | $ 81,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 5,000,000 | ||||||||
Benefit Payments, 2021 | 6,000,000 | ||||||||
Benefit Payments, 2022 | 6,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | 28,000,000 | ||||||||
Other postretirement benefit plans | GULF POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 7,000,000 | 6,000,000 | $ 7,000,000 | $ 5,000,000 | |||||
Other postretirement benefit plans | MISSISSIPPI POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Benefit Payments, 2019 | 6,000,000 | ||||||||
Benefit Payments, 2018 | 6,000,000 | ||||||||
Employer contributions | 4,000,000 | 4,000,000 | |||||||
Expected postretirement trust contributions | 0 | ||||||||
Projected benefit obligations | $ 97,000,000 | $ 97,000,000 | $ 97,000,000 | $ 97,000,000 | |||||
Annual salary increase on net periodic benefit costs | 4.46% | 4.46% | 3.59% | ||||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||||||
Target plan asset allocations (as percent) | 100.00% | ||||||||
Benefit Payments, 2020 | $ 6,000,000 | ||||||||
Benefit Payments, 2021 | 7,000,000 | ||||||||
Benefit Payments, 2022 | 7,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | $ 34,000,000 | ||||||||
Other postretirement benefit plans | MISSISSIPPI POWER CO | Fixed income | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Actual plan asset allocations (as percent) | 43.00% | 38.00% | 43.00% | ||||||
Target plan asset allocations (as percent) | 37.00% | ||||||||
Other postretirement benefit plans | MISSISSIPPI POWER CO | Regulatory Assets [Member] | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | $ 19,000,000 | $ 17,000,000 | $ 19,000,000 | $ 18,000,000 | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 1,000,000 | $ 1,000,000 | |||||||
Other postretirement benefit plans | SOUTHERN POWER CO | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax | 3,000,000 | ||||||||
Benefit Payments, 2019 | 4,000,000 | ||||||||
Benefit Payments, 2018 | 4,000,000 | ||||||||
Defined benefit plan, AOCI, gain (loss), before tax | (3,000,000) | ||||||||
Total accumulated benefit obligation for the pension plans | (11,000,000) | ||||||||
Projected benefit obligations | 11,000,000 | ||||||||
Benefit Payments, 2020 | 4,000,000 | ||||||||
Benefit Payments, 2021 | 4,000,000 | ||||||||
Benefit Payments, 2022 | 4,000,000 | ||||||||
Benefit Payments, 2023 to 2027 | 27,000,000 | ||||||||
Subsequent Event | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Defined contribution plan, employer matching contribution, percent of match | 6.00% | ||||||||
Defined contribution, maximum match of base salary | 5.10% | ||||||||
Qualified Plan | Pension plans | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Employer contributions | 0 | ||||||||
Expected postretirement trust contributions | 0 | ||||||||
Qualified Plan | Pension plans | SOUTHERN Co GAS | |||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||
Employer contributions | 0 | ||||||||
Expected postretirement trust contributions | $ 0 |
Retirement Benefits - Schedule
Retirement Benefits - Schedule of Health Care Cost Trend Rates (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |
Benefit obligation, 1 percent increase | $ 132 |
Benefit obligation, 1 percent decrease | 113 |
Service and interest costs, 1 percent increase | 4 |
Service and interest costs, 1 percent decrease | $ 3 |
Other postretirement benefit plans | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
Other postretirement benefit plans | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
Other postretirement benefit plans | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
SOUTHERN POWER CO | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
SOUTHERN POWER CO | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
SOUTHERN POWER CO | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
ALABAMA POWER CO | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |
Benefit obligation, 1 percent increase | $ 30 |
Benefit obligation, 1 percent decrease | 26 |
Service and interest costs, 1 percent increase | 1 |
Service and interest costs, 1 percent decrease | $ 1 |
ALABAMA POWER CO | Other postretirement benefit plans | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
ALABAMA POWER CO | Other postretirement benefit plans | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
ALABAMA POWER CO | Other postretirement benefit plans | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
GEORGIA POWER CO | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |
Benefit obligation, 1 percent increase | $ 59 |
Benefit obligation, 1 percent decrease | 50 |
Service and interest costs, 1 percent increase | 2 |
Service and interest costs, 1 percent decrease | $ 2 |
GEORGIA POWER CO | Other postretirement benefit plans | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
GEORGIA POWER CO | Other postretirement benefit plans | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
GEORGIA POWER CO | Other postretirement benefit plans | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
GULF POWER CO | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |
Benefit obligation, 1 percent increase | $ 4 |
Benefit obligation, 1 percent decrease | 3 |
Service and interest costs, 1 percent increase | 0 |
Service and interest costs, 1 percent decrease | $ 0 |
GULF POWER CO | Other postretirement benefit plans | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
GULF POWER CO | Other postretirement benefit plans | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
GULF POWER CO | Other postretirement benefit plans | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
MISSISSIPPI POWER CO | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |
Benefit obligation, 1 percent increase | $ 5 |
Benefit obligation, 1 percent decrease | 5 |
Service and interest costs, 1 percent increase | 0 |
Service and interest costs, 1 percent decrease | $ 0 |
MISSISSIPPI POWER CO | Other postretirement benefit plans | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
MISSISSIPPI POWER CO | Other postretirement benefit plans | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
MISSISSIPPI POWER CO | Other postretirement benefit plans | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,026 |
SOUTHERN Co GAS | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |
Benefit obligation, 1 percent increase | $ 11 |
Benefit obligation, 1 percent decrease | 10 |
Service and interest costs, 1 percent increase | 0 |
Service and interest costs, 1 percent decrease | $ 0 |
SOUTHERN Co GAS | Other postretirement benefit plans | Pre-65 | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.40% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,038 |
SOUTHERN Co GAS | Other postretirement benefit plans | Post-65 medical | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 7.80% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,038 |
SOUTHERN Co GAS | Other postretirement benefit plans | Post-65 prescription | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 7.80% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,038 |
Retirement Benefits - Changes i
Retirement Benefits - Changes in Projected Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) | Dec. 19, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | $ 10,542,000,000 | $ 12,385,000,000 | $ 10,542,000,000 | |||
Acquisitions | 0 | 1,244,000,000 | ||||
Service cost | 293,000,000 | 262,000,000 | $ 257,000,000 | |||
Interest cost | 455,000,000 | 422,000,000 | 445,000,000 | |||
Benefits paid | (596,000,000) | (466,000,000) | ||||
Actuarial loss (gain) | 1,297,000,000 | 342,000,000 | ||||
Plan amendments | (26,000,000) | 39,000,000 | ||||
Balance at end of year | $ 12,385,000,000 | 13,808,000,000 | 12,385,000,000 | 10,542,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 9,234,000,000 | 11,583,000,000 | 9,234,000,000 | |||
Acquisitions | 0 | 837,000,000 | ||||
Actual return (loss) on plan assets | 1,953,000,000 | 902,000,000 | ||||
Employer contributions | 52,000,000 | 1,076,000,000 | ||||
Benefits paid | (596,000,000) | (466,000,000) | ||||
Fair value of plan assets at end of year | 11,583,000,000 | 12,992,000,000 | 11,583,000,000 | 9,234,000,000 | ||
Accrued liability | (802,000,000) | (816,000,000) | (802,000,000) | |||
Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 1,989,000,000 | 2,297,000,000 | 1,989,000,000 | |||
Acquisitions | 0 | 338,000,000 | ||||
Service cost | 24,000,000 | 22,000,000 | 23,000,000 | |||
Interest cost | 79,000,000 | 76,000,000 | 78,000,000 | |||
Benefits paid | (136,000,000) | (119,000,000) | ||||
Actuarial loss (gain) | 65,000,000 | (16,000,000) | ||||
Plan amendments | 3,000,000 | 0 | ||||
Retiree drug subsidy | 7,000,000 | 7,000,000 | ||||
Balance at end of year | 2,297,000,000 | 2,339,000,000 | 2,297,000,000 | 1,989,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 833,000,000 | 944,000,000 | 833,000,000 | |||
Acquisitions | 0 | 100,000,000 | ||||
Actual return (loss) on plan assets | 154,000,000 | 58,000,000 | ||||
Employer contributions | 84,000,000 | 65,000,000 | ||||
Benefits paid | (129,000,000) | (112,000,000) | ||||
Fair value of plan assets at end of year | 944,000,000 | 1,053,000,000 | 944,000,000 | 833,000,000 | ||
Accrued liability | (1,353,000,000) | (1,286,000,000) | (1,353,000,000) | |||
GEORGIA POWER CO | Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 3,615,000,000 | 3,800,000,000 | 3,615,000,000 | |||
Service cost | 74,000,000 | 70,000,000 | 73,000,000 | |||
Interest cost | 138,000,000 | 136,000,000 | 154,000,000 | |||
Benefits paid | (187,000,000) | (164,000,000) | ||||
Actuarial loss (gain) | 363,000,000 | 143,000,000 | ||||
Balance at end of year | 3,800,000,000 | 4,188,000,000 | 3,800,000,000 | 3,615,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 3,196,000,000 | 3,621,000,000 | 3,196,000,000 | |||
Actual return (loss) on plan assets | 610,000,000 | 288,000,000 | ||||
Employer contributions | $ 0 | 14,000,000 | 301,000,000 | |||
Benefits paid | (187,000,000) | (164,000,000) | ||||
Fair value of plan assets at end of year | 3,621,000,000 | 4,058,000,000 | 3,621,000,000 | 3,196,000,000 | ||
Accrued liability | (179,000,000) | (130,000,000) | (179,000,000) | |||
GEORGIA POWER CO | Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 854,000,000 | 847,000,000 | 854,000,000 | |||
Service cost | 7,000,000 | 6,000,000 | 7,000,000 | |||
Interest cost | 29,000,000 | 30,000,000 | 34,000,000 | |||
Benefits paid | (51,000,000) | (45,000,000) | ||||
Actuarial loss (gain) | 28,000,000 | (1,000,000) | ||||
Retiree drug subsidy | 3,000,000 | 3,000,000 | ||||
Balance at end of year | 847,000,000 | 863,000,000 | 847,000,000 | 854,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 358,000,000 | 354,000,000 | 358,000,000 | |||
Actual return (loss) on plan assets | 54,000,000 | 21,000,000 | ||||
Employer contributions | 26,000,000 | 17,000,000 | ||||
Benefits paid | (48,000,000) | (42,000,000) | ||||
Fair value of plan assets at end of year | 354,000,000 | 386,000,000 | 354,000,000 | 358,000,000 | ||
Accrued liability | (493,000,000) | (477,000,000) | (493,000,000) | |||
ALABAMA POWER CO | Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 2,506,000,000 | 2,663,000,000 | 2,506,000,000 | |||
Service cost | 63,000,000 | 57,000,000 | 59,000,000 | |||
Interest cost | 98,000,000 | 95,000,000 | 106,000,000 | |||
Benefits paid | (120,000,000) | (109,000,000) | ||||
Actuarial loss (gain) | 294,000,000 | 114,000,000 | ||||
Balance at end of year | 2,663,000,000 | 2,998,000,000 | 2,663,000,000 | 2,506,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 2,279,000,000 | 2,517,000,000 | 2,279,000,000 | |||
Actual return (loss) on plan assets | 427,000,000 | 206,000,000 | ||||
Employer contributions | 0 | 12,000,000 | 141,000,000 | |||
Benefits paid | (120,000,000) | (109,000,000) | ||||
Fair value of plan assets at end of year | 2,517,000,000 | 2,836,000,000 | 2,517,000,000 | 2,279,000,000 | ||
Accrued liability | (146,000,000) | (162,000,000) | (146,000,000) | |||
ALABAMA POWER CO | Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 505,000,000 | 501,000,000 | 505,000,000 | |||
Service cost | 6,000,000 | 5,000,000 | 6,000,000 | |||
Interest cost | 17,000,000 | 18,000,000 | 20,000,000 | |||
Benefits paid | (29,000,000) | (28,000,000) | ||||
Actuarial loss (gain) | 20,000,000 | (1,000,000) | ||||
Retiree drug subsidy | 2,000,000 | 2,000,000 | ||||
Balance at end of year | 501,000,000 | 517,000,000 | 501,000,000 | 505,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 363,000,000 | 367,000,000 | 363,000,000 | |||
Actual return (loss) on plan assets | 60,000,000 | 23,000,000 | ||||
Employer contributions | 6,000,000 | 7,000,000 | ||||
Benefits paid | (27,000,000) | (26,000,000) | ||||
Fair value of plan assets at end of year | 367,000,000 | 406,000,000 | 367,000,000 | 363,000,000 | ||
Accrued liability | (134,000,000) | (111,000,000) | (134,000,000) | |||
GULF POWER CO | ||||||
Change in benefit obligation | ||||||
Service cost | 13,000,000 | 12,000,000 | 12,000,000 | |||
Interest cost | 19,000,000 | 19,000,000 | 20,000,000 | |||
GULF POWER CO | Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 480,000,000 | 517,000,000 | 480,000,000 | |||
Service cost | 13,000,000 | 12,000,000 | ||||
Interest cost | 19,000,000 | 19,000,000 | ||||
Benefits paid | (20,000,000) | (17,000,000) | ||||
Actuarial loss (gain) | 58,000,000 | 23,000,000 | ||||
Balance at end of year | 517,000,000 | 587,000,000 | 517,000,000 | 480,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 420,000,000 | 491,000,000 | 420,000,000 | |||
Actual return (loss) on plan assets | 81,000,000 | 39,000,000 | ||||
Employer contributions | 0 | 1,000,000 | 49,000,000 | |||
Benefits paid | (20,000,000) | (17,000,000) | ||||
Fair value of plan assets at end of year | 491,000,000 | 553,000,000 | 491,000,000 | 420,000,000 | ||
Accrued liability | (26,000,000) | (34,000,000) | (26,000,000) | |||
GULF POWER CO | Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 81,000,000 | 83,000,000 | 81,000,000 | |||
Service cost | 1,000,000 | 1,000,000 | 1,000,000 | |||
Interest cost | 3,000,000 | 3,000,000 | 3,000,000 | |||
Benefits paid | (5,000,000) | (4,000,000) | ||||
Actuarial loss (gain) | 1,000,000 | 2,000,000 | ||||
Balance at end of year | 83,000,000 | 83,000,000 | 83,000,000 | 81,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 17,000,000 | 18,000,000 | 17,000,000 | |||
Actual return (loss) on plan assets | 3,000,000 | 2,000,000 | ||||
Employer contributions | 4,000,000 | 3,000,000 | ||||
Benefits paid | (5,000,000) | (4,000,000) | ||||
Fair value of plan assets at end of year | 18,000,000 | 20,000,000 | 18,000,000 | 17,000,000 | ||
Accrued liability | (65,000,000) | (63,000,000) | (65,000,000) | |||
MISSISSIPPI POWER CO | ||||||
Change in benefit obligation | ||||||
Service cost | 15,000,000 | 13,000,000 | 13,000,000 | |||
Interest cost | 20,000,000 | 19,000,000 | 21,000,000 | |||
MISSISSIPPI POWER CO | Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 500,000,000 | 534,000,000 | 500,000,000 | |||
Service cost | 15,000,000 | 13,000,000 | ||||
Interest cost | 20,000,000 | 19,000,000 | ||||
Benefits paid | (22,000,000) | (20,000,000) | ||||
Actuarial loss (gain) | 55,000,000 | 22,000,000 | ||||
Balance at end of year | 534,000,000 | 602,000,000 | 534,000,000 | 500,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 430,000,000 | 499,000,000 | 430,000,000 | |||
Actual return (loss) on plan assets | 84,000,000 | 39,000,000 | ||||
Employer contributions | $ 0 | 2,000,000 | 50,000,000 | |||
Benefits paid | (22,000,000) | (20,000,000) | ||||
Fair value of plan assets at end of year | 499,000,000 | 563,000,000 | 499,000,000 | 430,000,000 | ||
Accrued liability | (35,000,000) | (39,000,000) | (35,000,000) | |||
MISSISSIPPI POWER CO | Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 97,000,000 | 97,000,000 | 97,000,000 | |||
Service cost | 1,000,000 | 1,000,000 | 1,000,000 | |||
Interest cost | 3,000,000 | 3,000,000 | 4,000,000 | |||
Benefits paid | (6,000,000) | (6,000,000) | ||||
Actuarial loss (gain) | 1,000,000 | 1,000,000 | ||||
Retiree drug subsidy | 1,000,000 | 1,000,000 | ||||
Balance at end of year | 97,000,000 | 97,000,000 | 97,000,000 | 97,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 23,000,000 | 23,000,000 | 23,000,000 | |||
Actual return (loss) on plan assets | 3,000,000 | 1,000,000 | ||||
Employer contributions | 4,000,000 | 4,000,000 | ||||
Benefits paid | (5,000,000) | (5,000,000) | ||||
Fair value of plan assets at end of year | 23,000,000 | 25,000,000 | 23,000,000 | 23,000,000 | ||
Accrued liability | (74,000,000) | (72,000,000) | (74,000,000) | |||
SOUTHERN Co GAS | ||||||
Change in benefit obligation | ||||||
Employee contributions | 1,000,000 | 3,000,000 | ||||
SOUTHERN Co GAS | Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 1,244,000,000 | 1,133,000,000 | ||||
Service cost | 15,000,000 | 23,000,000 | ||||
Interest cost | 20,000,000 | 42,000,000 | ||||
Benefits paid | (31,000,000) | (91,000,000) | ||||
Actuarial loss (gain) | (115,000,000) | 103,000,000 | ||||
Plan amendments | 0 | (26,000,000) | ||||
Balance at end of year | 1,133,000,000 | 1,244,000,000 | 1,184,000,000 | 1,133,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 837,000,000 | 983,000,000 | ||||
Actual return (loss) on plan assets | 48,000,000 | 175,000,000 | ||||
Employer contributions | 129,000,000 | 1,000,000 | ||||
Benefits paid | (31,000,000) | (91,000,000) | ||||
Fair value of plan assets at end of year | 983,000,000 | 837,000,000 | 1,068,000,000 | 983,000,000 | ||
Accrued liability | (150,000,000) | (116,000,000) | (150,000,000) | |||
SOUTHERN Co GAS | Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 338,000,000 | 308,000,000 | ||||
Service cost | 1,000,000 | 2,000,000 | ||||
Interest cost | 5,000,000 | 10,000,000 | ||||
Benefits paid | (11,000,000) | (19,000,000) | ||||
Actuarial loss (gain) | (26,000,000) | 3,000,000 | ||||
Plan amendments | 0 | 3,000,000 | ||||
Balance at end of year | 308,000,000 | 338,000,000 | 310,000,000 | 308,000,000 | ||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 100,000,000 | 105,000,000 | ||||
Actual return (loss) on plan assets | 4,000,000 | 20,000,000 | ||||
Employee contributions | 1,000,000 | 3,000,000 | ||||
Employer contributions | 11,000,000 | 17,000,000 | ||||
Benefits paid | (11,000,000) | (20,000,000) | ||||
Fair value of plan assets at end of year | 105,000,000 | 100,000,000 | 125,000,000 | 105,000,000 | ||
Accrued liability | (203,000,000) | (185,000,000) | (203,000,000) | |||
Predecessor | SOUTHERN Co GAS | ||||||
Change in benefit obligation | ||||||
Employee contributions | 1,000,000 | |||||
Predecessor | SOUTHERN Co GAS | Pension plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 1,244,000,000 | 1,067,000,000 | 1,067,000,000 | |||
Service cost | 13,000,000 | 28,000,000 | ||||
Interest cost | 21,000,000 | 45,000,000 | ||||
Benefits paid | (26,000,000) | |||||
Actuarial loss (gain) | 169,000,000 | |||||
Plan amendments | 0 | |||||
Balance at end of year | 1,244,000,000 | 1,067,000,000 | ||||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 837,000,000 | 847,000,000 | 847,000,000 | |||
Actual return (loss) on plan assets | 15,000,000 | |||||
Employer contributions | 1,000,000 | |||||
Benefits paid | (26,000,000) | |||||
Fair value of plan assets at end of year | 837,000,000 | 847,000,000 | ||||
Accrued liability | (407,000,000) | |||||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | 338,000,000 | 318,000,000 | ||||
Service cost | 1,000,000 | 2,000,000 | ||||
Interest cost | 5,000,000 | $ 13,000,000 | ||||
Benefits paid | (11,000,000) | |||||
Actuarial loss (gain) | 24,000,000 | |||||
Plan amendments | 0 | |||||
Balance at end of year | 318,000,000 | 338,000,000 | 318,000,000 | |||
Change in plan assets | ||||||
Fair value of plan assets at beginning of year | 100,000,000 | $ 99,000,000 | ||||
Actual return (loss) on plan assets | 1,000,000 | |||||
Employee contributions | 1,000,000 | |||||
Employer contributions | 10,000,000 | |||||
Benefits paid | (11,000,000) | |||||
Fair value of plan assets at end of year | $ 99,000,000 | 100,000,000 | $ 99,000,000 | |||
Accrued liability | $ (238,000,000) |
Retirement Benefits - Amounts R
Retirement Benefits - Amounts Recognized in Balance Sheets and Amounts in AOCI (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | $ 6,851 | $ 6,943 | $ 6,851 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 1,406 | 1,577 | 1,406 | ||
Other current liabilities | (925) | (868) | (925) | ||
Employee benefit obligations | (2,299) | (2,256) | (2,299) | ||
Other regulatory liabilities, deferred | (258) | (239) | (258) | ||
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 | 5,866 | (1,894) | 5,866 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (180) | (189) | (180) | ||
Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 3,207 | 3,273 | 3,207 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (53) | (53) | (53) | ||
Employee benefit obligations | (749) | (763) | (749) | ||
Other regulatory liabilities, deferred | (87) | (118) | (87) | ||
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 | 17 | 55 | ||
Amortization prior service costs | 5 | ||||
Net (Gain) Loss, Estimated | 213 | ||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 100 | 107 | 100 | ||
Pension plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 7 | 6 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 100 | 107 | 100 | $ 125 | |
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 | 3 | 4 | ||
Amortization prior service costs | 1 | ||||
Net (Gain) Loss, Estimated | 9 | ||||
Defined Benefit Plan Reclassification Adjustments | (8) | (7) | |||
Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 155 | 145 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 3,120 | 3,155 | 3,120 | 2,998 | |
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 | 14 | 51 | ||
Amortization prior service costs | 4 | ||||
Net (Gain) Loss, Estimated | 204 | ||||
Defined Benefit Plan Reclassification Adjustments | (166) | (158) | |||
Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 419 | 382 | 419 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (4) | (5) | (4) | ||
Employee benefit obligations | (1,349) | (1,281) | (1,349) | ||
Other regulatory liabilities, deferred | (41) | (41) | (41) | ||
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 | 25 | 21 | 25 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 7 | 4 | 7 | ||
Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 0 | 0 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 7 | 4 | 7 | 8 | |
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 | 0 | ||
Defined Benefit Plan Reclassification Adjustments | 0 | 0 | |||
Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 13 | 14 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 378 | 341 | 378 | 411 | |
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 | 25 | 21 | 25 | ||
Amortization prior service costs | 7 | ||||
Net (Gain) Loss, Estimated | 14 | ||||
Defined Benefit Plan Reclassification Adjustments | (19) | (20) | |||
ALABAMA POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 1,157 | 1,272 | 1,157 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 163 | 189 | 163 | ||
Other current liabilities | (76) | (59) | (76) | ||
Employee benefit obligations | (300) | (304) | (300) | ||
Other regulatory liabilities, deferred | (100) | (84) | (100) | ||
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 | 1,047 | (1,088) | 1,047 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (30) | (26) | (30) | ||
ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 870 | 890 | 870 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (12) | (12) | (12) | ||
Employee benefit obligations | (134) | (150) | (134) | ||
ALABAMA POWER CO | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 42 | 40 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 870 | 890 | 870 | 822 | |
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 | 10 | 8 | 10 | ||
Amortization prior service costs | 1 | ||||
Net (Gain) Loss, Estimated | 54 | ||||
Defined Benefit Plan Reclassification Adjustments | (44) | (43) | |||
ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 86 | 63 | 86 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Employee benefit obligations | (134) | (111) | (134) | ||
Other regulatory liabilities, deferred | (10) | (7) | (10) | ||
ALABAMA POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 76 | 56 | 76 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | 1 | 2 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 76 | 56 | 76 | 82 | |
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 | 11 | 15 | ||
Amortization prior service costs | 4 | ||||
Net (Gain) Loss, Estimated | 1 | ||||
Defined Benefit Plan Reclassification Adjustments | (5) | (6) | |||
GEORGIA POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 2,774 | 2,932 | 2,774 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Prepaid pension costs | 0 | 23 | 0 | ||
Other deferred charges and assets | 417 | 548 | 417 | ||
Other current liabilities | (182) | (198) | (182) | ||
Employee benefit obligations | (703) | (659) | (703) | ||
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 | 3,506 | 232 | 3,506 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (13) | (10) | (13) | ||
GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 1,129 | 1,105 | 1,129 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (14) | (15) | (14) | ||
Employee benefit obligations | (165) | (138) | (165) | ||
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 | 14 | 17 | ||
Amortization prior service costs | 2 | ||||
Net (Gain) Loss, Estimated | 69 | ||||
GEORGIA POWER CO | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 57 | 55 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 1,129 | 1,105 | 1,129 | 1,076 | |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (60) | (60) | |||
GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 213 | 202 | 213 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Employee benefit obligations | (493) | (477) | (493) | ||
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 | 6 | 5 | 6 | ||
Amortization prior service costs | 1 | ||||
Net (Gain) Loss, Estimated | 9 | ||||
GEORGIA POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 8 | 9 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 213 | 202 | 213 | 223 | |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (9) | (10) | |||
GULF POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 512 | 502 | 512 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 21 | 23 | 21 | ||
Other current liabilities | (24) | (27) | (24) | ||
Employee benefit obligations | (96) | (102) | (96) | ||
Other regulatory liabilities, deferred | (45) | (43) | (45) | ||
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 | 320 | (105) | 320 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 1 | 0 | 1 | ||
GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 153 | 160 | 153 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (1) | (1) | (1) | ||
Employee benefit obligations | (25) | (33) | (25) | ||
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 | 2 | 3 | ||
Amortization prior service costs | 0 | ||||
Net (Gain) Loss, Estimated | 10 | ||||
GULF POWER CO | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 7 | 6 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 153 | 160 | 153 | 142 | |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (8) | (7) | |||
GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 11 | 8 | 11 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (1) | (1) | (1) | ||
Employee benefit obligations | (64) | (62) | (64) | ||
Other regulatory liabilities, deferred | (4) | (2) | (4) | ||
GULF POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 7 | 6 | 7 | 5 | |
MISSISSIPPI POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 518 | 437 | 518 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 56 | 33 | 56 | ||
Other current liabilities | (36) | (82) | (36) | ||
Employee benefit obligations | (115) | (116) | (115) | ||
Other regulatory liabilities, deferred | (77) | (79) | (77) | ||
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 | 737 | (42) | 737 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (4) | (4) | (4) | ||
MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 154 | 158 | 154 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other current liabilities | (3) | (3) | (3) | ||
Employee benefit obligations | (32) | (36) | (32) | ||
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 | 3 | 3 | ||
Amortization prior service costs | 0 | ||||
Net (Gain) Loss, Estimated | 10 | ||||
MISSISSIPPI POWER CO | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 7 | 7 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 154 | 158 | 154 | 144 | |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (8) | (8) | |||
MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 21 | 18 | 21 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Employee benefit obligations | (74) | (72) | (74) | ||
Other regulatory liabilities, deferred | (2) | (1) | (2) | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 1 | 1 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 19 | 17 | 19 | 18 | |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (1) | (1) | |||
SOUTHERN POWER CO | |||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 628 | 566 | 628 | ||
Other current liabilities | (152) | (143) | (152) | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 35 | (2) | 35 | ||
SOUTHERN POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 33 | ||||
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 | 1 | ||||
Amortization prior service costs | 0 | ||||
Net (Gain) Loss, Estimated | 2 | ||||
SOUTHERN POWER CO | Other postretirement benefit plans | |||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 3 | ||||
Employee benefit obligations | (11) | ||||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Net (Gain) Loss, Estimated | 0 | ||||
SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 973 | 901 | 973 | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 170 | 218 | 170 | ||
Other current liabilities | (108) | (113) | (108) | ||
Employee benefit obligations | (441) | (415) | (441) | ||
Other regulatory liabilities, deferred | (29) | (30) | (29) | ||
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 | (715) | (1,879) | (715) | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 26 | 20 | 26 | ||
SOUTHERN Co GAS | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 40 | 0 | ||
Other Regulatory Assets Deferred | 267 | 217 | 267 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | (14) | (18) | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other deferred charges and assets | 58 | 85 | 58 | ||
Other current liabilities | (2) | (3) | (2) | ||
Employee benefit obligations | (206) | (198) | (206) | ||
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) | (20) | (2) | ||
SOUTHERN Co GAS | Pension plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 0 | 0 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | 0 | 0 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | (43) | $ 0 | (42) | (43) | |
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 | 0 | ||
Defined Benefit Plan Reclassification Adjustments | 0 | 0 | |||
SOUTHERN Co GAS | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 40 | 0 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | 15 | 18 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 267 | 368 | 217 | 267 | |
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) | (20) | (2) | ||
Amortization prior service costs | (2) | ||||
Net (Gain) Loss, Estimated | 16 | ||||
Defined Benefit Plan Reclassification Adjustments | (14) | (19) | |||
SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 6 | 0 | ||
Other Regulatory Assets Deferred | 52 | 46 | 52 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | 0 | (4) | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Employee benefit obligations | (203) | (185) | (203) | ||
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) | (7) | (12) | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 0 | 0 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | 0 | 0 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | (3) | 0 | (3) | (3) | |
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 | 0 | ||
Defined Benefit Plan Reclassification Adjustments | 0 | 0 | |||
SOUTHERN Co GAS | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 6 | 0 | ||
Defined Benefit Plan, Amortization of Gain (Loss) | 3 | 4 | |||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 52 | 77 | 46 | 52 | |
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) | (7) | $ (12) | ||
Defined Benefit Plan Reclassification Adjustments | $ (2) | $ (1) | |||
Predecessor | SOUTHERN Co GAS | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | (13) | (31) | |||
Predecessor | SOUTHERN Co GAS | Pension plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 9 | ||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 274 | 282 | |||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (8) | ||||
Predecessor | SOUTHERN Co GAS | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 4 | ||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 84 | 88 | |||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (4) | ||||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | (2) | (6) | |||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 1 | ||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 35 | 36 | |||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | (1) | ||||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Amortization of Gain (Loss) | 1 | ||||
Amounts recognized in the consolidated balance sheets related to company's pension plans | |||||
Other regulatory assets, deferred | 30 | $ 30 | |||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | |||||
Defined Benefit Plan Reclassification Adjustments | $ 0 |
Retirement Benefits - Component
Retirement Benefits - Components of Accumulated OCI and Changes in Regulatory Assets (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | $ 6,851 | $ 6,943 | $ 6,851 | ||
Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 25 | 21 | 25 | ||
Net (Gain) Loss | 360 | 324 | 360 | ||
Other Regulatory Assets Deferred | 419 | 382 | 419 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 20 | 21 | $ 21 | ||
Net periodic benefit cost | 57 | 59 | 64 | ||
Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 0 | 0 | 0 | ||
Net (Gain) Loss | 7 | 4 | 7 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | $ 8 | 7 | 8 | ||
Net (gain) loss | (3) | (1) | |||
Change in prior service costs | 0 | ||||
Reclassification adjustments | |||||
Amortization of prior service costs | 0 | 0 | |||
Amortization of net gain (loss) | 0 | 0 | |||
Total reclassification adjustments | 0 | 0 | |||
Net periodic benefit cost | (3) | (1) | |||
Ending Balance | 7 | 4 | 7 | 8 | |
Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 25 | 21 | 25 | ||
Amortization prior service costs | 7 | ||||
Net (Gain) Loss | 353 | 320 | 353 | ||
Amortization of gains (losses) | 14 | ||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 411 | 378 | 411 | ||
Net (gain) loss | (21) | (13) | |||
Change in prior service costs | 3 | ||||
Reclassification adjustments | |||||
Amortization of prior service costs | (6) | (6) | |||
Amortization of net gain (loss) | (13) | (14) | |||
Total reclassification adjustments | (19) | (20) | |||
Net periodic benefit cost | (37) | (33) | |||
Ending Balance | 378 | 341 | 378 | 411 | |
Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 55 | 17 | 55 | ||
Amortization prior service costs | 5 | ||||
Net (Gain) Loss | 3,165 | 3,244 | 3,165 | ||
Amortization of gains (losses) | 213 | ||||
Other Regulatory Assets Deferred | 3,207 | 3,273 | 3,207 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 12 | 14 | 25 | ||
Net periodic benefit cost | 25 | 66 | 218 | ||
Pension plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 4 | 3 | 4 | ||
Amortization prior service costs | 1 | ||||
Net (Gain) Loss | 96 | 104 | 96 | ||
Amortization of gains (losses) | 9 | ||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 125 | 100 | 125 | ||
Net (gain) loss | 15 | (20) | |||
Change in prior service costs | 0 | 2 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | (1) | |||
Amortization of net gain (loss) | (7) | (6) | |||
Total reclassification adjustments | (8) | (7) | |||
Net periodic benefit cost | 7 | (25) | |||
Ending Balance | 100 | 107 | 100 | 125 | |
Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 51 | 14 | 51 | ||
Amortization prior service costs | 4 | ||||
Net (Gain) Loss | 3,069 | 3,140 | 3,069 | ||
Amortization of gains (losses) | 204 | ||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 2,998 | 3,120 | 2,998 | ||
Net (gain) loss | 227 | 243 | |||
Change in prior service costs | (26) | 37 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (11) | (13) | |||
Amortization of net gain (loss) | (155) | (145) | |||
Total reclassification adjustments | (166) | (158) | |||
Net periodic benefit cost | 35 | 122 | |||
Ending Balance | 3,120 | 3,155 | 3,120 | 2,998 | |
MISSISSIPPI POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 518 | 437 | 518 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | 1 | 1 | ||
Net periodic benefit cost | 3 | 5 | 12 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 21 | 18 | 21 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | 1 | 1 | ||
Net periodic benefit cost | 4 | 4 | 4 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 18 | 19 | 18 | ||
Net (gain) loss | (1) | 2 | |||
Reclassification adjustments | |||||
Amortization of net gain (loss) | (1) | (1) | |||
Total reclassification adjustments | (1) | (1) | |||
Net periodic benefit cost | (2) | 1 | |||
Ending Balance | 19 | 17 | 19 | 18 | |
MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 3 | 3 | 3 | ||
Amortization prior service costs | 0 | ||||
Net (Gain) Loss | 151 | 155 | 151 | ||
Amortization of gains (losses) | 10 | ||||
Other Regulatory Assets Deferred | 154 | 158 | 154 | ||
MISSISSIPPI POWER CO | Pension plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 144 | 154 | 144 | ||
Net (gain) loss | 12 | 16 | |||
Change in prior service costs | 0 | 2 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | (1) | |||
Amortization of net gain (loss) | (7) | (7) | |||
Total reclassification adjustments | (8) | (8) | |||
Net periodic benefit cost | 4 | 10 | |||
Ending Balance | 154 | 158 | 154 | 144 | |
ALABAMA POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 1,157 | 1,272 | 1,157 | ||
ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 86 | 63 | 86 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 5 | 6 | 5 | ||
Net periodic benefit cost | 3 | 4 | 5 | ||
ALABAMA POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 15 | 11 | 15 | ||
Amortization prior service costs | 4 | ||||
Net (Gain) Loss | 61 | 45 | 61 | ||
Amortization of gains (losses) | 1 | ||||
Other Regulatory Assets Deferred | 76 | 56 | 76 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 82 | 76 | 82 | ||
Net (gain) loss | (15) | 0 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (4) | (4) | |||
Amortization of net gain (loss) | (1) | (2) | |||
Total reclassification adjustments | (5) | (6) | |||
Net periodic benefit cost | (20) | (6) | |||
Ending Balance | 76 | 56 | 76 | 82 | |
ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 870 | 890 | 870 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 2 | 3 | 6 | ||
Net periodic benefit cost | 9 | 11 | 48 | ||
ALABAMA POWER CO | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 10 | 8 | 10 | ||
Amortization prior service costs | 1 | ||||
Net (Gain) Loss | 860 | 882 | 860 | ||
Amortization of gains (losses) | 54 | ||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 822 | 870 | 822 | ||
Net (gain) loss | 64 | 84 | |||
Change in prior service costs | 0 | 7 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (2) | (3) | |||
Amortization of net gain (loss) | (42) | (40) | |||
Total reclassification adjustments | (44) | (43) | |||
Net periodic benefit cost | 20 | 48 | |||
Ending Balance | 870 | 890 | 870 | 822 | |
GEORGIA POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 2,774 | 2,932 | 2,774 | ||
GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 6 | 5 | 6 | ||
Amortization prior service costs | 1 | ||||
Net (Gain) Loss | 207 | 197 | 207 | ||
Amortization of gains (losses) | 9 | ||||
Other Regulatory Assets Deferred | 213 | 202 | 213 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 9 | 10 | 11 | ||
Net periodic benefit cost | 20 | 24 | 28 | ||
GEORGIA POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 223 | 213 | 223 | ||
Net (gain) loss | (2) | 0 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | (1) | |||
Amortization of net gain (loss) | (8) | (9) | |||
Total reclassification adjustments | (9) | (10) | |||
Net periodic benefit cost | (11) | (10) | |||
Ending Balance | 213 | 202 | 213 | 223 | |
GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 17 | 14 | 17 | ||
Amortization prior service costs | 2 | ||||
Net (Gain) Loss | 1,112 | 1,091 | 1,112 | ||
Amortization of gains (losses) | 69 | ||||
Other Regulatory Assets Deferred | 1,129 | 1,105 | 1,129 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 3 | 5 | 9 | ||
Net periodic benefit cost | (11) | 8 | 61 | ||
GEORGIA POWER CO | Pension plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 1,076 | 1,129 | 1,076 | ||
Net (gain) loss | 36 | 99 | |||
Change in prior service costs | 0 | 14 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (3) | (5) | |||
Amortization of net gain (loss) | (57) | (55) | |||
Total reclassification adjustments | (60) | (60) | |||
Net periodic benefit cost | (24) | 53 | |||
Ending Balance | 1,129 | 1,105 | 1,129 | 1,076 | |
GULF POWER CO | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 512 | 502 | 512 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | 1 | 1 | ||
Net periodic benefit cost | 2 | 4 | 10 | ||
GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Net (Gain) Loss | (7) | (6) | (7) | ||
Other Regulatory Assets Deferred | 11 | 8 | 11 | ||
Reclassification adjustments | |||||
Net periodic benefit cost | 3 | 3 | 3 | ||
GULF POWER CO | Other postretirement benefit plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 5 | 7 | 5 | ||
Net (gain) loss | (1) | 2 | |||
Reclassification adjustments | |||||
Ending Balance | 7 | 6 | 7 | 5 | |
GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 3 | 2 | 3 | ||
Amortization prior service costs | 0 | ||||
Net (Gain) Loss | 150 | 158 | 150 | ||
Amortization of gains (losses) | 10 | ||||
Other Regulatory Assets Deferred | 153 | 160 | 153 | ||
GULF POWER CO | Pension plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 142 | 153 | 142 | ||
Net (gain) loss | 15 | 16 | |||
Change in prior service costs | 0 | 2 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | (1) | |||
Amortization of net gain (loss) | (7) | (6) | |||
Total reclassification adjustments | (8) | (7) | |||
Net periodic benefit cost | 7 | 11 | |||
Ending Balance | 153 | 160 | 153 | 142 | |
SOUTHERN POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Net (Gain) Loss | 3 | ||||
Amortization of gains (losses) | 0 | ||||
Reclassification adjustments | |||||
Ending Balance | 3 | ||||
SOUTHERN POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 1 | ||||
Amortization prior service costs | 0 | ||||
Net (Gain) Loss | 32 | ||||
Amortization of gains (losses) | 2 | ||||
Other Regulatory Assets Deferred | 33 | ||||
SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other Regulatory Assets Deferred | 973 | 901 | 973 | ||
SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | (12) | (7) | (12) | ||
Net (Gain) Loss | (61) | (44) | (61) | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 6 | 0 | ||
Other Regulatory Assets Deferred | 52 | 46 | 52 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Amortization of regulatory assets | 2 | 0 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | 0 | (3) | |||
Amortization of net gain (loss) | 0 | 4 | |||
Net periodic benefit cost | 5 | 6 | |||
SOUTHERN Co GAS | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 0 | 0 | 0 | ||
Net (Gain) Loss | 3 | 3 | 3 | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 0 | 0 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 0 | (3) | |||
Net (gain) loss | (3) | 0 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | 0 | 0 | |||
Amortization of net gain (loss) | 0 | 0 | |||
Total reclassification adjustments | 0 | 0 | |||
Net periodic benefit cost | (3) | 0 | |||
Ending Balance | (3) | 0 | (3) | (3) | |
SOUTHERN Co GAS | Other postretirement benefit plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | (12) | (7) | (12) | ||
Net (Gain) Loss | (64) | (47) | (64) | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 6 | 0 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 77 | 52 | |||
Net (gain) loss | (23) | (5) | |||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | 3 | |||
Amortization of net gain (loss) | (3) | (4) | |||
Total reclassification adjustments | (2) | (1) | |||
Net periodic benefit cost | (25) | (6) | |||
Ending Balance | 52 | 77 | 46 | 52 | |
SOUTHERN Co GAS | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | (2) | (20) | (2) | ||
Net (Gain) Loss | 226 | 155 | 226 | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 40 | 0 | ||
Other Regulatory Assets Deferred | 267 | 217 | 267 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Amortization of regulatory assets | 0 | 1 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | 0 | |||
Amortization of net gain (loss) | 14 | 18 | |||
Net periodic benefit cost | 13 | 14 | |||
SOUTHERN Co GAS | Pension plans | Accumulated Other Comprehensive Income (Loss) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | 0 | 0 | 0 | ||
Net (Gain) Loss | (43) | (42) | (43) | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 0 | 0 | ||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 0 | (43) | |||
Net (gain) loss | (43) | 1 | |||
Amortization of regulatory assets | 0 | ||||
Reclassification adjustments | |||||
Amortization of prior service costs | 0 | ||||
Amortization of net gain (loss) | 0 | 0 | |||
Total reclassification adjustments | 0 | 0 | |||
Net periodic benefit cost | (43) | 1 | |||
Ending Balance | (43) | 0 | (42) | (43) | |
SOUTHERN Co GAS | Pension plans | Regulatory Assets | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Prior Service Cost | (2) | (20) | (2) | ||
Amortization prior service costs | (2) | ||||
Net (Gain) Loss | 269 | 197 | 269 | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization | 0 | 40 | 0 | ||
Amortization of gains (losses) | 16 | ||||
Defined Benefit Plan, Accumulated Other Comprehensive Income, Regulatory Amortization, Next Twelve Months | 3 | ||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 368 | 267 | |||
Net (gain) loss | (87) | (31) | |||
Amortization of regulatory assets | (1) | ||||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | ||||
Amortization of net gain (loss) | (15) | (18) | |||
Total reclassification adjustments | (14) | (19) | |||
Net periodic benefit cost | (101) | (50) | |||
Ending Balance | 267 | 368 | $ 217 | 267 | |
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Amortization of regulatory assets | 0 | 0 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | (3) | |||
Amortization of net gain (loss) | 2 | 6 | |||
Net periodic benefit cost | 4 | 11 | |||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 35 | 36 | 36 | ||
Net (gain) loss | 0 | ||||
Reclassification adjustments | |||||
Amortization of prior service costs | 0 | ||||
Amortization of net gain (loss) | (1) | ||||
Total reclassification adjustments | (1) | ||||
Net periodic benefit cost | (1) | ||||
Ending Balance | 35 | 36 | |||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 30 | 30 | 30 | ||
Net (gain) loss | 0 | ||||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | ||||
Amortization of net gain (loss) | (1) | ||||
Total reclassification adjustments | 0 | ||||
Net periodic benefit cost | 0 | ||||
Ending Balance | 30 | 30 | |||
Predecessor | SOUTHERN Co GAS | Pension plans | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Amortization of regulatory assets | 0 | 0 | |||
Reclassification adjustments | |||||
Amortization of prior service costs | (1) | (2) | |||
Amortization of net gain (loss) | 13 | 31 | |||
Net periodic benefit cost | 13 | 37 | |||
Predecessor | SOUTHERN Co GAS | Pension plans | Accumulated Other Comprehensive Income (Loss) | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | 274 | 282 | 282 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 1 | ||||
Amortization of net gain (loss) | (9) | ||||
Total reclassification adjustments | (8) | ||||
Net periodic benefit cost | (8) | ||||
Ending Balance | 274 | 282 | |||
Predecessor | SOUTHERN Co GAS | Pension plans | Regulatory Assets | |||||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||||
Beginning Balance | $ 84 | 88 | $ 88 | ||
Reclassification adjustments | |||||
Amortization of prior service costs | 0 | ||||
Amortization of net gain (loss) | (4) | ||||
Total reclassification adjustments | (4) | ||||
Net periodic benefit cost | (4) | ||||
Ending Balance | $ 84 | $ 88 |
Retirement Benefits - Compone67
Retirement Benefits - Components of Net Periodic Benefit Cost and Estimated Future Benefit Payments (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | ||||
Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 24 | $ 22 | $ 23 | ||
Interest cost | 79 | 76 | 78 | ||
Expected return on plan assets | (66) | (60) | (58) | ||
Net amortization | 20 | 21 | 21 | ||
Net periodic benefit cost | 57 | $ 59 | 64 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 144 | ||||
Benefit Payments, 2019 | 148 | ||||
Benefit Payments, 2020 | 151 | ||||
Benefit Payments, 2021 | 154 | ||||
Benefit Payments, 2022 | 156 | ||||
Benefit Payments, 2023 to 2027 | 780 | ||||
Subsidy Receipts | |||||
Subsidy Receipts, 2018 | (7) | ||||
Subsidy Receipts, 2019 | (8) | ||||
Subsidy Receipts, 2020 | (8) | ||||
Subsidy Receipts, 2021 | (9) | ||||
Subsidy Receipts, 2022 | (9) | ||||
Subsidy Receipts, 2023 to 2027 | (48) | ||||
Benefit Payments and Subsidy Receipts, Total | |||||
Benefit Payments and Subsidy Receipts, 2017 | 137 | ||||
Benefit Payments and Subsidy Receipts, 2018 | 140 | ||||
Benefit Payments and Subsidy Receipts, 2019 | 143 | ||||
Benefit Payments and Subsidy Receipts, 2020 | 145 | ||||
Benefit Payments and Subsidy Receipts, 2021 | 147 | ||||
Benefit Payments and Subsidy Receipts, 2022 to 2026 | 732 | ||||
Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | |||
Components of net periodic | |||||
Service cost | 293 | $ 262 | 257 | ||
Interest cost | 455 | 422 | 445 | ||
Expected return on plan assets | (897) | (782) | (724) | ||
Recognized net (gain) loss | 162 | 150 | 215 | ||
Net amortization | 12 | 14 | 25 | ||
Net periodic benefit cost | 25 | $ 66 | 218 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 634 | ||||
Benefit Payments, 2019 | 637 | ||||
Benefit Payments, 2020 | 663 | ||||
Benefit Payments, 2021 | 681 | ||||
Benefit Payments, 2022 | 704 | ||||
Benefit Payments, 2023 to 2027 | $ 3,836 | ||||
ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 6 | $ 5 | 6 | ||
Interest cost | 17 | 18 | 20 | ||
Expected return on plan assets | (25) | (25) | (26) | ||
Net amortization | 5 | 6 | 5 | ||
Net periodic benefit cost | 3 | $ 4 | 5 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 31 | ||||
Benefit Payments, 2019 | 32 | ||||
Benefit Payments, 2020 | 33 | ||||
Benefit Payments, 2021 | 34 | ||||
Benefit Payments, 2022 | 35 | ||||
Benefit Payments, 2023 to 2027 | 173 | ||||
Subsidy Receipts | |||||
Subsidy Receipts, 2018 | (2) | ||||
Subsidy Receipts, 2019 | (2) | ||||
Subsidy Receipts, 2020 | (3) | ||||
Subsidy Receipts, 2021 | (3) | ||||
Subsidy Receipts, 2022 | (3) | ||||
Subsidy Receipts, 2023 to 2027 | (14) | ||||
Benefit Payments and Subsidy Receipts, Total | |||||
Benefit Payments and Subsidy Receipts, 2017 | 29 | ||||
Benefit Payments and Subsidy Receipts, 2018 | 30 | ||||
Benefit Payments and Subsidy Receipts, 2019 | 30 | ||||
Benefit Payments and Subsidy Receipts, 2020 | 31 | ||||
Benefit Payments and Subsidy Receipts, 2021 | 32 | ||||
Benefit Payments and Subsidy Receipts, 2022 to 2026 | $ 159 | ||||
ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 63 | $ 57 | 59 | ||
Interest cost | 98 | 95 | 106 | ||
Expected return on plan assets | (196) | (184) | (178) | ||
Recognized net (gain) loss | 42 | 40 | 55 | ||
Net amortization | 2 | 3 | 6 | ||
Net periodic benefit cost | 9 | $ 11 | 48 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 129 | ||||
Benefit Payments, 2019 | 134 | ||||
Benefit Payments, 2020 | 139 | ||||
Benefit Payments, 2021 | 143 | ||||
Benefit Payments, 2022 | 148 | ||||
Benefit Payments, 2023 to 2027 | $ 807 | ||||
GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 7 | $ 6 | 7 | ||
Interest cost | 29 | 30 | 34 | ||
Expected return on plan assets | (25) | (22) | (24) | ||
Net amortization | 9 | 10 | 11 | ||
Net periodic benefit cost | 20 | $ 24 | 28 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 55 | ||||
Benefit Payments, 2019 | 55 | ||||
Benefit Payments, 2020 | 56 | ||||
Benefit Payments, 2021 | 57 | ||||
Benefit Payments, 2022 | 58 | ||||
Benefit Payments, 2023 to 2027 | 288 | ||||
Subsidy Receipts | |||||
Subsidy Receipts, 2018 | (3) | ||||
Subsidy Receipts, 2019 | (3) | ||||
Subsidy Receipts, 2020 | (3) | ||||
Subsidy Receipts, 2021 | (4) | ||||
Subsidy Receipts, 2022 | (4) | ||||
Subsidy Receipts, 2023 to 2027 | (21) | ||||
Benefit Payments and Subsidy Receipts, Total | |||||
Benefit Payments and Subsidy Receipts, 2017 | 52 | ||||
Benefit Payments and Subsidy Receipts, 2018 | 52 | ||||
Benefit Payments and Subsidy Receipts, 2019 | 53 | ||||
Benefit Payments and Subsidy Receipts, 2020 | 53 | ||||
Benefit Payments and Subsidy Receipts, 2021 | 54 | ||||
Benefit Payments and Subsidy Receipts, 2022 to 2026 | $ 267 | ||||
GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 74 | $ 70 | 73 | ||
Interest cost | 138 | 136 | 154 | ||
Expected return on plan assets | (283) | (258) | (251) | ||
Recognized net (gain) loss | 57 | 55 | 76 | ||
Net amortization | 3 | 5 | 9 | ||
Net periodic benefit cost | (11) | 8 | 61 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 196 | ||||
Benefit Payments, 2019 | 201 | ||||
Benefit Payments, 2020 | 207 | ||||
Benefit Payments, 2021 | 210 | ||||
Benefit Payments, 2022 | 216 | ||||
Benefit Payments, 2023 to 2027 | 1,156 | ||||
GULF POWER CO | |||||
Components of net periodic | |||||
Service cost | 13 | 12 | 12 | ||
Interest cost | 19 | 19 | 20 | ||
Expected return on plan assets | (38) | (34) | (32) | ||
Recognized net (gain) loss | 7 | 6 | 9 | ||
Net amortization | 1 | 1 | 1 | ||
Net periodic benefit cost | $ 2 | $ 4 | 10 | ||
GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 1 | $ 1 | 1 | ||
Interest cost | 3 | 3 | 3 | ||
Expected return on plan assets | (1) | (1) | (1) | ||
Net periodic benefit cost | 3 | $ 3 | 3 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 5 | ||||
Benefit Payments, 2019 | 5 | ||||
Benefit Payments, 2020 | 5 | ||||
Benefit Payments, 2021 | 6 | ||||
Benefit Payments, 2022 | 6 | ||||
Benefit Payments, 2023 to 2027 | 28 | ||||
Subsidy Receipts | |||||
Subsidy Receipts, 2018 | 0 | ||||
Subsidy Receipts, 2019 | 0 | ||||
Subsidy Receipts, 2020 | 0 | ||||
Subsidy Receipts, 2021 | (1) | ||||
Subsidy Receipts, 2022 | (1) | ||||
Subsidy Receipts, 2023 to 2027 | (2) | ||||
Benefit Payments and Subsidy Receipts, Total | |||||
Benefit Payments and Subsidy Receipts, 2017 | 5 | ||||
Benefit Payments and Subsidy Receipts, 2018 | 5 | ||||
Benefit Payments and Subsidy Receipts, 2019 | 5 | ||||
Benefit Payments and Subsidy Receipts, 2020 | 5 | ||||
Benefit Payments and Subsidy Receipts, 2021 | 5 | ||||
Benefit Payments and Subsidy Receipts, 2022 to 2026 | $ 26 | ||||
GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 13 | $ 12 | |||
Interest cost | 19 | 19 | |||
Benefit Payments | |||||
Benefit Payments, 2018 | 22 | ||||
Benefit Payments, 2019 | 23 | ||||
Benefit Payments, 2020 | 25 | ||||
Benefit Payments, 2021 | 26 | ||||
Benefit Payments, 2022 | 28 | ||||
Benefit Payments, 2023 to 2027 | 155 | ||||
MISSISSIPPI POWER CO | |||||
Components of net periodic | |||||
Service cost | 15 | 13 | 13 | ||
Interest cost | 20 | 19 | 21 | ||
Expected return on plan assets | (40) | (35) | (33) | ||
Recognized net (gain) loss | 7 | 7 | 10 | ||
Net amortization | 1 | 1 | 1 | ||
Net periodic benefit cost | $ 3 | $ 5 | 12 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 1 | $ 1 | 1 | ||
Interest cost | 3 | 3 | 4 | ||
Expected return on plan assets | (1) | (1) | (2) | ||
Net amortization | 1 | 1 | 1 | ||
Net periodic benefit cost | 4 | $ 4 | 4 | ||
Benefit Payments | |||||
Benefit Payments, 2018 | 6 | ||||
Benefit Payments, 2019 | 6 | ||||
Benefit Payments, 2020 | 6 | ||||
Benefit Payments, 2021 | 7 | ||||
Benefit Payments, 2022 | 7 | ||||
Benefit Payments, 2023 to 2027 | 34 | ||||
Subsidy Receipts | |||||
Subsidy Receipts, 2018 | 0 | ||||
Subsidy Receipts, 2019 | 0 | ||||
Subsidy Receipts, 2020 | (1) | ||||
Subsidy Receipts, 2021 | (1) | ||||
Subsidy Receipts, 2022 | (1) | ||||
Subsidy Receipts, 2023 to 2027 | (2) | ||||
Benefit Payments and Subsidy Receipts, Total | |||||
Benefit Payments and Subsidy Receipts, 2017 | 6 | ||||
Benefit Payments and Subsidy Receipts, 2018 | 6 | ||||
Benefit Payments and Subsidy Receipts, 2019 | 5 | ||||
Benefit Payments and Subsidy Receipts, 2020 | 6 | ||||
Benefit Payments and Subsidy Receipts, 2021 | 6 | ||||
Benefit Payments and Subsidy Receipts, 2022 to 2026 | $ 32 | ||||
MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 15 | $ 13 | |||
Interest cost | 20 | $ 19 | |||
Benefit Payments | |||||
Benefit Payments, 2018 | 23 | ||||
Benefit Payments, 2019 | 24 | ||||
Benefit Payments, 2020 | 26 | ||||
Benefit Payments, 2021 | 27 | ||||
Benefit Payments, 2022 | 28 | ||||
Benefit Payments, 2023 to 2027 | $ 164 | ||||
SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
Components of net periodic | |||||
Service cost | $ 1 | $ 2 | |||
Interest cost | 5 | 10 | |||
Expected return on plan assets | (3) | (7) | |||
Amortization of regulatory assets | 2 | 0 | |||
Net amortization | 0 | (3) | |||
Defined Benefit Plan, Amortization of Gain (Loss) | 0 | (4) | |||
Net periodic benefit cost | 5 | 6 | |||
Benefit Payments | |||||
Benefit Payments, 2018 | 20 | ||||
Benefit Payments, 2019 | 20 | ||||
Benefit Payments, 2020 | 21 | ||||
Benefit Payments, 2021 | 21 | ||||
Benefit Payments, 2022 | 22 | ||||
Benefit Payments, 2023 to 2027 | 105 | ||||
SOUTHERN Co GAS | Pension plans | |||||
Components of net periodic | |||||
Service cost | 15 | 23 | |||
Interest cost | 20 | 42 | |||
Expected return on plan assets | (35) | (70) | |||
Amortization of regulatory assets | 0 | 1 | |||
Net amortization | (1) | 0 | |||
Defined Benefit Plan, Amortization of Gain (Loss) | (14) | (18) | |||
Net periodic benefit cost | $ 13 | 14 | |||
Benefit Payments | |||||
Benefit Payments, 2018 | 100 | ||||
Benefit Payments, 2019 | 77 | ||||
Benefit Payments, 2020 | 79 | ||||
Benefit Payments, 2021 | 79 | ||||
Benefit Payments, 2022 | 80 | ||||
Benefit Payments, 2023 to 2027 | $ 392 | ||||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Components of net periodic | |||||
Service cost | $ 1 | 2 | |||
Interest cost | 5 | 13 | |||
Expected return on plan assets | (3) | (7) | |||
Amortization of regulatory assets | 0 | 0 | |||
Net amortization | (1) | (3) | |||
Defined Benefit Plan, Amortization of Gain (Loss) | (2) | (6) | |||
Net periodic benefit cost | 4 | 11 | |||
Predecessor | SOUTHERN Co GAS | Pension plans | |||||
Components of net periodic | |||||
Service cost | 13 | 28 | |||
Interest cost | 21 | 45 | |||
Expected return on plan assets | (33) | (65) | |||
Amortization of regulatory assets | 0 | 0 | |||
Net amortization | (1) | (2) | |||
Defined Benefit Plan, Amortization of Gain (Loss) | (13) | (31) | |||
Net periodic benefit cost | $ 13 | $ 37 | |||
Equity Securities | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 72.00% | ||||
Actual plan asset allocations (as percent) | 74.00% | 76.00% | 74.00% | ||
Fixed income | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 29.00% | 30.00% | 29.00% | ||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | 31.00% | ||
Fixed income | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 23.00% | 23.00% | 23.00% | ||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||
Fixed income | ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 23.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||
Fixed income | GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 23.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||
Fixed income | GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 23.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||
Fixed income | MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 37.00% | ||||
Actual plan asset allocations (as percent) | 43.00% | 38.00% | 43.00% | ||
Fixed income | MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 23.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 24.00% | 29.00% | ||
Fixed income | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 24.00% | ||||
Actual plan asset allocations (as percent) | 23.00% | 20.00% | 23.00% | ||
Domestic equity | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 39.00% | 37.00% | 39.00% | ||
Actual plan asset allocations (as percent) | 40.00% | 40.00% | 40.00% | ||
Domestic equity | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 26.00% | 26.00% | 26.00% | ||
Actual plan asset allocations (as percent) | 29.00% | 31.00% | 29.00% | ||
Domestic equity | ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 42.00% | ||||
Actual plan asset allocations (as percent) | 44.00% | 44.00% | 44.00% | ||
Domestic equity | ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 26.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 31.00% | 29.00% | ||
Domestic equity | GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 36.00% | ||||
Actual plan asset allocations (as percent) | 35.00% | 38.00% | 35.00% | ||
Domestic equity | GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 26.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 31.00% | 29.00% | ||
Domestic equity | GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | ||||
Actual plan asset allocations (as percent) | 28.00% | 30.00% | 28.00% | ||
Domestic equity | GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 26.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 31.00% | 29.00% | ||
Domestic equity | MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 21.00% | ||||
Actual plan asset allocations (as percent) | 23.00% | 25.00% | 23.00% | ||
Domestic equity | MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 26.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 31.00% | 29.00% | ||
Special situations | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 1.00% | 1.00% | 1.00% | ||
Actual plan asset allocations (as percent) | 1.00% | 1.00% | 1.00% | ||
Special situations | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | 3.00% | 3.00% | ||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
Special situations | ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 1.00% | ||||
Actual plan asset allocations (as percent) | 1.00% | 0.00% | 1.00% | ||
Special situations | ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
Special situations | GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 1.00% | ||||
Actual plan asset allocations (as percent) | 1.00% | 1.00% | 1.00% | ||
Special situations | GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
Special situations | GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
Special situations | GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
Special situations | MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 2.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
Special situations | MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | 2.00% | ||
International equity | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 23.00% | 23.00% | 23.00% | ||
Actual plan asset allocations (as percent) | 21.00% | 23.00% | 21.00% | ||
International equity | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | 25.00% | 25.00% | ||
Actual plan asset allocations (as percent) | 22.00% | 25.00% | 22.00% | ||
International equity | ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 22.00% | ||||
Actual plan asset allocations (as percent) | 20.00% | 22.00% | 20.00% | ||
International equity | ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | ||||
Actual plan asset allocations (as percent) | 22.00% | 25.00% | 22.00% | ||
International equity | GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 24.00% | ||||
Actual plan asset allocations (as percent) | 24.00% | 24.00% | 24.00% | ||
International equity | GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | ||||
Actual plan asset allocations (as percent) | 22.00% | 25.00% | 22.00% | ||
International equity | GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 24.00% | ||||
Actual plan asset allocations (as percent) | 21.00% | 24.00% | 21.00% | ||
International equity | GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | ||||
Actual plan asset allocations (as percent) | 22.00% | 25.00% | 22.00% | ||
International equity | MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 21.00% | ||||
Actual plan asset allocations (as percent) | 18.00% | 20.00% | 18.00% | ||
International equity | MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | ||||
Actual plan asset allocations (as percent) | 22.00% | 25.00% | 22.00% | ||
Domestic Fixed Income Investments | ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 28.00% | ||||
Actual plan asset allocations (as percent) | 29.00% | 28.00% | 29.00% | ||
Domestic Fixed Income Investments | GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 33.00% | ||||
Actual plan asset allocations (as percent) | 35.00% | 31.00% | 35.00% | ||
Domestic Fixed Income Investments | GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 25.00% | ||||
Actual plan asset allocations (as percent) | 31.00% | 26.00% | 31.00% | ||
Real Estate Investment | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 5.00% | 5.00% | 5.00% | ||
Actual plan asset allocations (as percent) | 5.00% | 5.00% | 5.00% | ||
Real Estate Investment | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 14.00% | 14.00% | 14.00% | ||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | 13.00% | ||
Real Estate Investment | ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 4.00% | ||||
Actual plan asset allocations (as percent) | 4.00% | 4.00% | 4.00% | ||
Real Estate Investment | ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 14.00% | ||||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | 13.00% | ||
Real Estate Investment | GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 4.00% | ||||
Actual plan asset allocations (as percent) | 4.00% | 4.00% | 4.00% | ||
Real Estate Investment | GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 14.00% | ||||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | 13.00% | ||
Real Estate Investment | GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 14.00% | ||||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | 13.00% | ||
Real Estate Investment | GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 14.00% | ||||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | 13.00% | ||
Real Estate Investment | MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 12.00% | ||||
Actual plan asset allocations (as percent) | 10.00% | 11.00% | 10.00% | ||
Real Estate Investment | MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 14.00% | ||||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | 13.00% | ||
Private Equity Funds | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | 4.00% | 3.00% | ||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | 2.00% | ||
Private Equity Funds | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 9.00% | 9.00% | 9.00% | ||
Actual plan asset allocations (as percent) | 5.00% | 6.00% | 5.00% | ||
Private Equity Funds | ALABAMA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | 2.00% | ||
Private Equity Funds | ALABAMA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 9.00% | ||||
Actual plan asset allocations (as percent) | 5.00% | 6.00% | 5.00% | ||
Private Equity Funds | GEORGIA POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 2.00% | ||||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | 1.00% | ||
Private Equity Funds | GEORGIA POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 9.00% | ||||
Actual plan asset allocations (as percent) | 5.00% | 6.00% | 5.00% | ||
Private Equity Funds | GULF POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 9.00% | ||||
Actual plan asset allocations (as percent) | 5.00% | 6.00% | 5.00% | ||
Private Equity Funds | GULF POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 9.00% | ||||
Actual plan asset allocations (as percent) | 5.00% | 6.00% | 5.00% | ||
Private Equity Funds | MISSISSIPPI POWER CO | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 7.00% | ||||
Actual plan asset allocations (as percent) | 4.00% | 5.00% | 4.00% | ||
Private Equity Funds | MISSISSIPPI POWER CO | Pension plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 9.00% | ||||
Actual plan asset allocations (as percent) | 5.00% | 6.00% | 5.00% | ||
Cash and Cash Equivalents | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 1.00% | ||||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | 1.00% | ||
Other Types Of Investments | SOUTHERN Co GAS | Other postretirement benefit plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 3.00% | ||||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | 2.00% | ||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 100.00% | ||||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | 100.00% | ||
AGL Resources Inc. Retirement Plan | Equity Securities | SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 53.00% | ||||
Actual plan asset allocations (as percent) | 69.00% | 65.00% | 69.00% | ||
AGL Resources Inc. Retirement Plan | Fixed income | SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 15.00% | ||||
Actual plan asset allocations (as percent) | 20.00% | 19.00% | 20.00% | ||
AGL Resources Inc. Retirement Plan | Cash and Cash Equivalents | SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 2.00% | ||||
Actual plan asset allocations (as percent) | 1.00% | 6.00% | 1.00% | ||
AGL Resources Inc. Retirement Plan | Other Types Of Investments | SOUTHERN Co GAS | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Target plan asset allocations (as percent) | 30.00% | ||||
Actual plan asset allocations (as percent) | 10.00% | 10.00% | 10.00% |
Retirement Benefits - Fair Valu
Retirement Benefits - Fair Values of Pension Plan and Other Postretirement Benefit Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2015 |
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | |||
Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 12,992 | $ 11,583 | $ 9,234 | |
Assets Fair Value | ||||
Fair value, plan assets | 11,956 | 10,583 | ||
Alternative investments | 2,037 | $ 1,881 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | |||
Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 3,564 | $ 2,937 | ||
Target plan asset allocations (as percent) | 26.00% | 26.00% | ||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | ||
Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 2,958 | $ 2,341 | ||
Target plan asset allocations (as percent) | 25.00% | 25.00% | ||
Actual plan asset allocations (as percent) | 25.00% | 22.00% | ||
Pension plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 23.00% | 23.00% | ||
Actual plan asset allocations (as percent) | 24.00% | 29.00% | ||
Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 841 | $ 588 | ||
Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 8 | 13 | ||
Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,201 | 991 | ||
Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 650 | 524 | ||
Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 228 | 998 | ||
Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,657 | 1,462 | ||
Alternative investments | $ 1,188 | $ 1,152 | ||
Target plan asset allocations (as percent) | 14.00% | 14.00% | ||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | ||
Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 180 | $ 180 | ||
Alternative investments | $ 180 | $ 180 | ||
Target plan asset allocations (as percent) | 3.00% | 3.00% | ||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 669 | $ 549 | ||
Alternative investments | $ 669 | $ 549 | ||
Target plan asset allocations (as percent) | 9.00% | 9.00% | ||
Actual plan asset allocations (as percent) | 6.00% | 5.00% | ||
Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 1,053 | $ 944 | 833 | |
Assets Fair Value | ||||
Fair value, plan assets | 927 | 838 | ||
Alternative investments | $ 61 | $ 57 | ||
Target plan asset allocations (as percent) | 100.00% | 100.00% | ||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 167 | $ 146 | ||
Target plan asset allocations (as percent) | 37.00% | 39.00% | ||
Actual plan asset allocations (as percent) | 40.00% | 40.00% | ||
Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 123 | $ 98 | ||
Target plan asset allocations (as percent) | 23.00% | 23.00% | ||
Actual plan asset allocations (as percent) | 23.00% | 21.00% | ||
Other postretirement benefit plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 30.00% | 29.00% | ||
Actual plan asset allocations (as percent) | 29.00% | 31.00% | ||
Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 32 | $ 24 | ||
Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 37 | 30 | ||
Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 55 | 49 | ||
Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 10 | 41 | ||
Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 426 | 382 | ||
Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 52 | 46 | ||
Alternative investments | $ 36 | $ 35 | ||
Target plan asset allocations (as percent) | 5.00% | 5.00% | ||
Actual plan asset allocations (as percent) | 5.00% | 5.00% | ||
Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 5 | $ 5 | ||
Alternative investments | $ 5 | $ 5 | ||
Target plan asset allocations (as percent) | 1.00% | 1.00% | ||
Actual plan asset allocations (as percent) | 1.00% | 1.00% | ||
Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 20 | $ 17 | ||
Alternative investments | $ 20 | $ 17 | ||
Target plan asset allocations (as percent) | 4.00% | 3.00% | ||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 4,646 | $ 4,547 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2,405 | 2,010 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,555 | 1,231 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 217 | 996 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 469 | 310 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 205 | 207 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 132 | 118 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 47 | 37 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 10 | 41 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 16 | 11 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 5,273 | 4,155 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,159 | 927 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,403 | 1,110 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 841 | 588 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 8 | 13 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,201 | 991 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 650 | 524 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 11 | 2 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 661 | 574 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 35 | 28 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 76 | 61 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 32 | 24 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 37 | 30 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 55 | 49 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 426 | 382 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 2,836 | 2,517 | 2,279 | |
Assets Fair Value | ||||
Fair value, plan assets | 2,844 | 2,513 | ||
Alternative investments | $ 485 | $ 447 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
ALABAMA POWER CO | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 848 | $ 697 | ||
Target plan asset allocations (as percent) | 26.00% | |||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | ||
ALABAMA POWER CO | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 703 | $ 556 | ||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 25.00% | 22.00% | ||
ALABAMA POWER CO | Pension plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 23.00% | |||
Actual plan asset allocations (as percent) | 24.00% | 29.00% | ||
ALABAMA POWER CO | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 200 | $ 140 | ||
ALABAMA POWER CO | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 3 | ||
ALABAMA POWER CO | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 286 | 235 | ||
ALABAMA POWER CO | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 155 | 124 | ||
ALABAMA POWER CO | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 54 | 237 | ||
ALABAMA POWER CO | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 394 | 348 | ||
Alternative investments | $ 283 | $ 274 | ||
Target plan asset allocations (as percent) | 14.00% | |||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | ||
ALABAMA POWER CO | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 43 | $ 43 | ||
Alternative investments | $ 43 | $ 43 | ||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
ALABAMA POWER CO | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 159 | $ 130 | ||
Alternative investments | $ 159 | $ 130 | ||
Target plan asset allocations (as percent) | 9.00% | |||
Actual plan asset allocations (as percent) | 6.00% | 5.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 406 | $ 367 | 363 | |
Assets Fair Value | ||||
Fair value, plan assets | 405 | 366 | ||
Alternative investments | $ 21 | $ 20 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 64 | $ 61 | ||
Target plan asset allocations (as percent) | 42.00% | |||
Actual plan asset allocations (as percent) | 44.00% | 44.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 30 | $ 25 | ||
Target plan asset allocations (as percent) | 22.00% | |||
Actual plan asset allocations (as percent) | 22.00% | 20.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | Domestic Fixed Income Investments | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 28.00% | |||
Actual plan asset allocations (as percent) | 28.00% | 29.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 11 | $ 7 | ||
ALABAMA POWER CO | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 12 | 10 | ||
ALABAMA POWER CO | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 7 | 5 | ||
ALABAMA POWER CO | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 14 | ||
ALABAMA POWER CO | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 253 | 220 | ||
ALABAMA POWER CO | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 17 | 16 | ||
Alternative investments | $ 12 | $ 12 | ||
Target plan asset allocations (as percent) | 4.00% | |||
Actual plan asset allocations (as percent) | 4.00% | 4.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 2 | $ 2 | ||
Alternative investments | $ 2 | $ 2 | ||
Target plan asset allocations (as percent) | 1.00% | |||
Actual plan asset allocations (as percent) | 0.00% | 1.00% | ||
ALABAMA POWER CO | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 7 | $ 6 | ||
Alternative investments | $ 7 | $ 6 | ||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1,104 | $ 1,079 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 572 | 477 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 370 | 292 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 51 | 236 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 111 | 74 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 75 | 82 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 52 | 51 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 16 | 13 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 14 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 5 | 4 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,255 | 987 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 276 | 220 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 333 | 264 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 200 | 140 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 3 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 286 | 235 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 155 | 124 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 1 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 309 | 264 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 12 | 10 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 14 | 12 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 11 | 7 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 12 | 10 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 7 | 5 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 253 | 220 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 563 | 499 | 430 | |
Assets Fair Value | ||||
Fair value, plan assets | 564 | 498 | ||
Alternative investments | $ 97 | $ 88 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
MISSISSIPPI POWER CO | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 168 | $ 139 | ||
Target plan asset allocations (as percent) | 26.00% | |||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | ||
MISSISSIPPI POWER CO | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 139 | $ 109 | ||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 25.00% | 22.00% | ||
MISSISSIPPI POWER CO | Pension plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 23.00% | |||
Actual plan asset allocations (as percent) | 24.00% | 29.00% | ||
MISSISSIPPI POWER CO | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 40 | $ 28 | ||
MISSISSIPPI POWER CO | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | |||
MISSISSIPPI POWER CO | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 56 | 46 | ||
MISSISSIPPI POWER CO | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 31 | 25 | ||
MISSISSIPPI POWER CO | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 11 | 47 | ||
MISSISSIPPI POWER CO | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 78 | 69 | ||
Alternative investments | $ 56 | $ 54 | ||
Target plan asset allocations (as percent) | 14.00% | |||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | ||
MISSISSIPPI POWER CO | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 9 | $ 8 | ||
Alternative investments | $ 9 | $ 8 | ||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
MISSISSIPPI POWER CO | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 32 | $ 26 | ||
Alternative investments | $ 32 | $ 26 | ||
Target plan asset allocations (as percent) | 9.00% | |||
Actual plan asset allocations (as percent) | 6.00% | 5.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 25 | $ 23 | 23 | |
Assets Fair Value | ||||
Fair value, plan assets | 24 | 24 | ||
Alternative investments | $ 3 | $ 3 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 6 | $ 6 | ||
Target plan asset allocations (as percent) | 21.00% | |||
Actual plan asset allocations (as percent) | 25.00% | 23.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 5 | $ 4 | ||
Target plan asset allocations (as percent) | 21.00% | |||
Actual plan asset allocations (as percent) | 20.00% | 18.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 37.00% | |||
Actual plan asset allocations (as percent) | 38.00% | 43.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 5 | $ 5 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 2 | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 3 | ||
Alternative investments | $ 2 | $ 2 | ||
Target plan asset allocations (as percent) | 12.00% | |||
Actual plan asset allocations (as percent) | 11.00% | 10.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 2.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
MISSISSIPPI POWER CO | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1 | $ 1 | ||
Alternative investments | $ 1 | $ 1 | ||
Target plan asset allocations (as percent) | 7.00% | |||
Actual plan asset allocations (as percent) | 5.00% | 4.00% | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 218 | $ 215 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 113 | 95 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 73 | 58 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 10 | 47 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 22 | 15 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 9 | 9 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 4 | 4 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 2 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 2 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 249 | 195 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 55 | 44 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 66 | 51 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 40 | 28 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | |||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 56 | 46 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 31 | 25 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 12 | 12 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 5 | 5 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 4,058 | 3,621 | 3,196 | |
Assets Fair Value | ||||
Fair value, plan assets | 4,069 | 3,615 | ||
Alternative investments | $ 693 | $ 643 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
GEORGIA POWER CO | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1,213 | $ 1,003 | ||
Target plan asset allocations (as percent) | 26.00% | |||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | ||
GEORGIA POWER CO | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1,006 | $ 800 | ||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 25.00% | 22.00% | ||
GEORGIA POWER CO | Pension plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 23.00% | |||
Actual plan asset allocations (as percent) | 24.00% | 29.00% | ||
GEORGIA POWER CO | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 286 | $ 201 | ||
GEORGIA POWER CO | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 4 | ||
GEORGIA POWER CO | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 409 | 338 | ||
GEORGIA POWER CO | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 221 | 179 | ||
GEORGIA POWER CO | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 78 | 341 | ||
GEORGIA POWER CO | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 564 | 500 | ||
Alternative investments | $ 404 | $ 394 | ||
Target plan asset allocations (as percent) | 14.00% | |||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | ||
GEORGIA POWER CO | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 61 | $ 61 | ||
Alternative investments | $ 61 | $ 61 | ||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
GEORGIA POWER CO | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 228 | $ 188 | ||
Alternative investments | $ 228 | $ 188 | ||
Target plan asset allocations (as percent) | 9.00% | |||
Actual plan asset allocations (as percent) | 6.00% | 5.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 386 | $ 354 | 358 | |
Assets Fair Value | ||||
Fair value, plan assets | 384 | 352 | ||
Alternative investments | $ 19 | $ 18 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 64 | $ 54 | ||
Target plan asset allocations (as percent) | 36.00% | |||
Actual plan asset allocations (as percent) | 38.00% | 35.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 60 | $ 48 | ||
Target plan asset allocations (as percent) | 24.00% | |||
Actual plan asset allocations (as percent) | 24.00% | 24.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | Domestic Fixed Income Investments | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 33.00% | |||
Actual plan asset allocations (as percent) | 31.00% | 35.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 6 | $ 5 | ||
GEORGIA POWER CO | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 11 | 9 | ||
GEORGIA POWER CO | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 41 | 38 | ||
GEORGIA POWER CO | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 4 | 15 | ||
GEORGIA POWER CO | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 173 | 162 | ||
GEORGIA POWER CO | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 17 | 14 | ||
Alternative investments | $ 11 | $ 11 | ||
Target plan asset allocations (as percent) | 4.00% | |||
Actual plan asset allocations (as percent) | 4.00% | 4.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 2 | $ 2 | ||
Alternative investments | $ 2 | $ 2 | ||
Target plan asset allocations (as percent) | 1.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 1.00% | ||
GEORGIA POWER CO | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 6 | $ 5 | ||
Alternative investments | $ 6 | $ 5 | ||
Target plan asset allocations (as percent) | 2.00% | |||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1,582 | $ 1,552 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 819 | 686 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 529 | 420 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 74 | 340 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 160 | 106 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 77 | 74 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 53 | 45 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 14 | 11 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 4 | 15 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 6 | 3 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1,794 | 1,420 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 394 | 317 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 477 | 380 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 286 | 201 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 4 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 409 | 338 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 221 | 179 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 4 | 1 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 288 | 260 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 11 | 9 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 46 | 37 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 6 | 5 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 11 | 9 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 41 | 38 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 173 | 162 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Trust-owned life insurance | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 553 | 491 | 420 | |
Assets Fair Value | ||||
Fair value, plan assets | 555 | 490 | ||
Alternative investments | $ 94 | $ 86 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
GULF POWER CO | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 166 | $ 136 | ||
Target plan asset allocations (as percent) | 26.00% | |||
Actual plan asset allocations (as percent) | 31.00% | 29.00% | ||
GULF POWER CO | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 137 | $ 109 | ||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 25.00% | 22.00% | ||
GULF POWER CO | Pension plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 23.00% | |||
Actual plan asset allocations (as percent) | 24.00% | 29.00% | ||
GULF POWER CO | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 39 | $ 27 | ||
GULF POWER CO | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | |||
GULF POWER CO | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 57 | 47 | ||
GULF POWER CO | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 30 | 24 | ||
GULF POWER CO | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 10 | 46 | ||
GULF POWER CO | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 77 | 67 | ||
Alternative investments | $ 55 | $ 53 | ||
Target plan asset allocations (as percent) | 14.00% | |||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | ||
GULF POWER CO | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 8 | $ 8 | ||
Alternative investments | $ 8 | $ 8 | ||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
GULF POWER CO | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 31 | $ 25 | ||
Alternative investments | $ 31 | $ 25 | ||
Target plan asset allocations (as percent) | 9.00% | |||
Actual plan asset allocations (as percent) | 6.00% | 5.00% | ||
GULF POWER CO | Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 20 | $ 18 | 17 | |
Assets Fair Value | ||||
Fair value, plan assets | 19 | 19 | ||
Alternative investments | $ 3 | $ 3 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
GULF POWER CO | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 6 | $ 5 | ||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 30.00% | 28.00% | ||
GULF POWER CO | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 4 | $ 4 | ||
Target plan asset allocations (as percent) | 24.00% | |||
Actual plan asset allocations (as percent) | 24.00% | 21.00% | ||
GULF POWER CO | Other postretirement benefit plans | Domestic Fixed Income Investments | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 26.00% | 31.00% | ||
GULF POWER CO | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1 | $ 1 | ||
GULF POWER CO | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
GULF POWER CO | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
GULF POWER CO | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 2 | ||
GULF POWER CO | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 3 | ||
Alternative investments | $ 2 | $ 2 | ||
Target plan asset allocations (as percent) | 14.00% | |||
Actual plan asset allocations (as percent) | 13.00% | 13.00% | ||
GULF POWER CO | Other postretirement benefit plans | Special situations | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 1.00% | 2.00% | ||
GULF POWER CO | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 1 | $ 1 | ||
Alternative investments | $ 1 | $ 1 | ||
Target plan asset allocations (as percent) | 9.00% | |||
Actual plan asset allocations (as percent) | 6.00% | 5.00% | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 216 | $ 210 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 112 | 93 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 72 | 57 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 10 | 46 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 22 | 14 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 8 | 8 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 4 | 3 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 2 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 245 | 194 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 54 | 43 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 65 | 52 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 39 | 27 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | |||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 57 | 47 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 30 | 24 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 8 | 8 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 2 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 1 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
GULF POWER CO | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN POWER CO | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 138 | |||
Alternative investments | $ 24 | |||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | |||
SOUTHERN POWER CO | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 41 | |||
Target plan asset allocations (as percent) | 26.00% | |||
Actual plan asset allocations (as percent) | 31.00% | |||
SOUTHERN POWER CO | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 34 | |||
Target plan asset allocations (as percent) | 25.00% | |||
Actual plan asset allocations (as percent) | 25.00% | |||
SOUTHERN POWER CO | Pension plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 23.00% | |||
Actual plan asset allocations (as percent) | 24.00% | |||
SOUTHERN POWER CO | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 10 | |||
SOUTHERN POWER CO | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 14 | |||
SOUTHERN POWER CO | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 8 | |||
SOUTHERN POWER CO | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | |||
SOUTHERN POWER CO | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 19 | |||
Alternative investments | $ 14 | |||
Target plan asset allocations (as percent) | 14.00% | |||
Actual plan asset allocations (as percent) | 13.00% | |||
SOUTHERN POWER CO | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 2 | |||
Alternative investments | $ 2 | |||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 1.00% | |||
SOUTHERN POWER CO | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 8 | |||
Alternative investments | $ 8 | |||
Target plan asset allocations (as percent) | 9.00% | |||
Actual plan asset allocations (as percent) | 6.00% | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 53 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 28 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 18 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 5 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 61 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 13 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 16 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 10 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 14 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 8 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN Co GAS | Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1,068 | 983 | $ 837 | |
Assets Fair Value | ||||
Fair value, plan assets | 945 | 983 | ||
Alternative investments | 65 | 100 | ||
SOUTHERN Co GAS | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 478 | 485 | ||
SOUTHERN Co GAS | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 166 | 185 | ||
SOUTHERN Co GAS | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 85 | 85 | ||
SOUTHERN Co GAS | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 39 | 41 | ||
SOUTHERN Co GAS | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 66 | |||
SOUTHERN Co GAS | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 157 | 100 | ||
Alternative investments | 48 | 83 | ||
SOUTHERN Co GAS | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 19 | 19 | ||
Alternative investments | 16 | 15 | ||
SOUTHERN Co GAS | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 1 | 2 | ||
Alternative investments | 1 | 2 | ||
SOUTHERN Co GAS | Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 125 | 105 | 100 | |
Assets Fair Value | ||||
Fair value, plan assets | 121 | 105 | ||
Alternative investments | $ 1 | $ 2 | ||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Cash and Cash Equivalents | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 1.00% | |||
Actual plan asset allocations (as percent) | 2.00% | 1.00% | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 72 | $ 61 | ||
SOUTHERN Co GAS | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 22 | $ 18 | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 24.00% | |||
Actual plan asset allocations (as percent) | 20.00% | 23.00% | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 24 | $ 23 | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 3 | ||
Alternative investments | $ 1 | $ 2 | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Equity Securities | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 72.00% | |||
Actual plan asset allocations (as percent) | 76.00% | 74.00% | ||
SOUTHERN Co GAS | Other postretirement benefit plans | Other Types Of Investments | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 3.00% | |||
Actual plan asset allocations (as percent) | 2.00% | 2.00% | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 242 | $ 158 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 155 | 142 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 84 | 12 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 4 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 5 | 4 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 3 | 3 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 2 | 1 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 638 | 725 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 323 | 343 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 166 | 185 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 85 | 85 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 39 | 41 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 66 | |||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 25 | 5 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 115 | 99 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 69 | 58 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 22 | 18 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 24 | 23 | ||
SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | |||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds | ||||
Assets Fair Value | ||||
Fair value, plan assets | 0 | 0 | ||
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other | ||||
Assets Fair Value | ||||
Fair value, plan assets | $ 0 | 0 | ||
Predecessor | SOUTHERN Co GAS | Pension plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 837 | $ 847 | ||
Predecessor | SOUTHERN Co GAS | Other postretirement benefit plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 99 | $ 100 | ||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 100.00% | |||
Actual plan asset allocations (as percent) | 100.00% | 100.00% | ||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Cash and Cash Equivalents | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 2.00% | |||
Actual plan asset allocations (as percent) | 6.00% | 1.00% | ||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Fixed income | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 15.00% | |||
Actual plan asset allocations (as percent) | 19.00% | 20.00% | ||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Equity Securities | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 53.00% | |||
Actual plan asset allocations (as percent) | 65.00% | 69.00% | ||
AGL Resources Inc. Retirement Plan | SOUTHERN Co GAS | Other Types Of Investments | ||||
Assets Fair Value | ||||
Target plan asset allocations (as percent) | 30.00% | |||
Actual plan asset allocations (as percent) | 10.00% | 10.00% |
Contingencies and Regulatory 69
Contingencies and Regulatory Matters - Textual - SO Environmental & FERC Matters (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | |
GEORGIA POWER CO | |||
Loss Contingencies [Line Items] | |||
Environmental exit costs, assets previously disposed, liability for remediation | $ 22 | $ 17 | |
Claims awarded to companies related to nuclear fuel disposal litigation | $ 18 | ||
GULF POWER CO | |||
Loss Contingencies [Line Items] | |||
Environmental exit costs, assets previously disposed, liability for remediation | 52 | 44 | |
SOUTHERN Co GAS | |||
Loss Contingencies [Line Items] | |||
Environmental exit costs, costs accrued to date | 388 | $ 426 | |
ALABAMA POWER CO | |||
Loss Contingencies [Line Items] | |||
Claims awarded to companies related to nuclear fuel disposal litigation | $ 26 | ||
Location One | SOUTHERN Co GAS | |||
Loss Contingencies [Line Items] | |||
Environmental exit costs, assets previously disposed, liability for remediation | $ 2 |
Contingencies and Regulatory 70
Contingencies and Regulatory Matters - Textual - SO Regulatory Matters APC (Details) - ALABAMA POWER CO | Jan. 01, 2019$ / KWH_Kilowatt_hour | Jan. 01, 2018$ / KWH_Kilowatt_hour | Apr. 30, 2016MW | Dec. 31, 2017USD ($) | Dec. 31, 2015MW | Feb. 17, 2017USD ($) | Jan. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2014 |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Adjusting point of weighted cost of equity | 5.98% | ||||||||
Percent of basis points | 0.07% | ||||||||
Percent of designated customer value benchmark survey | 33.33% | 33.33% | |||||||
Rate adjustment period | 2 years | ||||||||
Maximum percentage of rate RSE | 4.00% | ||||||||
Maximum annual percentage of ratio R\rate | 5.00% | ||||||||
Rate RSE refund liability | $ 73,000,000 | ||||||||
Rate RSE increase | 4.48% | ||||||||
Rate RSE increase amount | $ 245,000,000 | ||||||||
Tax cuts and jobs act, anticipated retail revenue reduction, next twelve months | $ 250,000,000 | ||||||||
Under recovered certified power purchase agreements | 12,000,000 | 142,000,000 | |||||||
Over (under) recovered environmental clause | 17,000,000 | 9,000,000 | |||||||
Over recovered fuel cost | 25,000,000 | $ 76,000,000 | |||||||
Minimum natural disaster reserve balance, triggering establishment charge | 50,000,000 | ||||||||
Natural disaster reserve, expected collection annually until reserve is restored | 16,000,000 | ||||||||
Natural disaster reserve authorized limit | $ 75,000,000 | ||||||||
Maximum period for recovery deferred stock related operations and maintenance costs and any future reserve deficits | 24 months | ||||||||
Maximum rate NDR charge per month, monthly nonresidential customer account | $ 10 | ||||||||
Maximum rate NDR charge per month, monthly residential customer account | 5 | ||||||||
Natural disaster reserve | $ 38,000,000 | ||||||||
Minimum | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Weighted cost of equity | 5.75% | ||||||||
Potential period for next depreciation study | 2 years | ||||||||
Maximum | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Weighted cost of equity | 6.21% | ||||||||
Potential period for next depreciation study | 4 years | ||||||||
Regulatory Assets | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Under recovered certified power purchase agreements | $ 69,000,000 | ||||||||
Over (under) recovered environmental clause | $ (36,000,000) | ||||||||
Plant Gorgas Units 6 and 7 | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Capacity of units included in request for decertification of units | MW | 200 | ||||||||
Plant Barry Unit 3 | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Capacity of units included in request for decertification of units | MW | 225 | ||||||||
Plant Barry Units 1 And 2 | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Capacity of units included in request for decertification of units | MW | 250 | ||||||||
Plant Greene County Units 1 And 2 | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Capacity of units included in request for decertification of units | MW | 300 | ||||||||
Subsequent Event | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Current billing rates under rate ECR in terms of per units | $ / KWH_Kilowatt_hour | 0.02015 | ||||||||
Scenario, Forecast | |||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||
Current billing rates under rate ECR in terms of per units | $ / KWH_Kilowatt_hour | 0.05910 |
Contingencies and Regulatory 71
Contingencies and Regulatory Matters - Textual - SO Regulatory GPC (Details) $ in Millions | Jan. 01, 2013 | Jul. 31, 2016MW | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)MW | Dec. 31, 2022 | Jun. 30, 2019USD ($) | Dec. 31, 2016USD ($) | Aug. 31, 2016 | May 01, 2016USD ($) | Jan. 01, 2016USD ($) | Dec. 31, 2015USD ($) |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Other regulatory assets, current | $ 604 | $ 581 | |||||||||
Other regulatory assets, deferred | $ 6,943 | 6,851 | |||||||||
Scenario, Forecast | Customers | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Percentage basis net merger savings | 60.00% | ||||||||||
Georgia Power And Atlanta Gas Light Company | Scenario, Forecast | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Percentage basis net merger savings | 40.00% | ||||||||||
GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Increase (decrease) in base tariff rate | $ 49 | ||||||||||
Increase (decrease) in ECCR tariff | 75 | ||||||||||
Increase (decrease) in demand side management tariff | 3 | ||||||||||
Increase (decrease) in municipal franchise fee tariff | 13 | ||||||||||
Increase (decrease) in revenue to be received from base rate change | $ 140 | ||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||
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% | ||||||||||
Capacity of units included in application request by subsidiaries for future period requests | MW | 1,200 | ||||||||||
Capacity of renewable resources approved for self-build | MW | 200 | ||||||||||
Approved capacity of units for solar generation resources | MW | 510 | ||||||||||
Approved increase (decrease) in annual billing based on fuel cost recovery rate | $ (313) | $ (350) | |||||||||
Adjustment to fuel cost recovery rate if under recovered fuel balance exceeds budget thereafter | $ 200 | ||||||||||
Required period for options and hedges | 48 months | ||||||||||
Over recovered fuel balance | $ 165 | 84 | |||||||||
Accrual under alternate rate plan | 30 | ||||||||||
Other regulatory assets, current | 205 | 193 | |||||||||
Other regulatory assets, deferred | 2,932 | 2,774 | |||||||||
GEORGIA POWER CO | Scenario, Forecast | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Customer refund | $ 44 | ||||||||||
Minimum | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Retail rate of return on common equity | 10.00% | ||||||||||
Maximum | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Retail rate of return on common equity | 12.00% | ||||||||||
Capacity of renewable resources considered for renewable commercial and industrial program | MW | 200 | ||||||||||
Maximum | GEORGIA POWER CO | Scenario, Forecast | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Cost recovery, new nuclear | $ 99 | ||||||||||
Cost recovery, estimate, nuclear fuel | $ 50 | ||||||||||
Plant Mitchell Units 3, 4A, and 4B | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Capacity of units included in request for decertification of units | MW | 217 | ||||||||||
Plant Kraft Unit 1 | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Capacity of units included in request for decertification of units | MW | 17 | ||||||||||
Intercession City Combustion Turbine | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Capacity of units included in request to sell | MW | 143 | ||||||||||
Percent ownership | 33.00% | ||||||||||
Storm damage reserves | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Incremental restoration costs | 260 | ||||||||||
Property damage reserves-liability | GEORGIA POWER CO | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Regulatory asset | 333 | 206 | |||||||||
Other regulatory assets, current | 30 | 30 | |||||||||
Other regulatory assets, deferred | $ 303 | $ 176 |
Contingencies and Regulatory 72
Contingencies and Regulatory Matters - Textual - SO Regulatory Matters GULF (Details) | Jan. 01, 2018MW | Jul. 01, 2017 | Mar. 31, 2017MW | Jun. 30, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2019USD ($) |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Other cost of removal obligations | $ 2,684,000,000 | $ 2,748,000,000 | ||||||||
GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Other cost of removal obligations | 221,000,000 | 249,000,000 | ||||||||
Reduction in depreciation expense | $ 34,000,000 | 0 | $ 20,100,000 | $ 8,400,000 | ||||||
Retail rate of return on common equity | 10.25% | |||||||||
Retail regulatory equity ratio | 0.525 | |||||||||
Loss on Plant Scherer Unit 3 | $ 33,000,000 | $ 0 | $ 0 | |||||||
Settlement Agreement | GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Other cost of removal obligations | $ 62,500,000 | |||||||||
Scenario, Forecast | GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Increase retail base rate, cost recovery credit | $ 8,000,000 | |||||||||
Retail regulatory equity ratio | 0.535 | |||||||||
Rate case settlement annual reduction base rates | $ 18,200,000 | |||||||||
Rate case settlement annual reduction environmental cost recovery rate | 15,600,000 | |||||||||
Tax reform settlement refund | $ 69,400,000 | |||||||||
Minimum | GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Retail rate of return on common equity | 9.25% | |||||||||
Maximum | GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Retail rate of return on common equity | 11.25% | |||||||||
Plant Smith Units 1 and 2 | GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Capacity of units written down | MW | 205 | |||||||||
Subsequent Event | Plant Smith Units 1 and 2 | GULF POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Capacity of units approved for decertification | MW | 357 | |||||||||
Capacity of units approved for decertification, amortization period | 15 years |
Contingencies and Regulatory 73
Contingencies and Regulatory Matters - Textual - So Regulatory Matters MPC (Details) - MISSISSIPPI POWER CO - USD ($) $ in Millions | Feb. 07, 2018 | Dec. 31, 2013 |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Annual PEP filing rate increase amount | $ 15 | |
Subsequent Event | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Annual PEP filing rate increase amount | $ 26 | |
Public utilities, approved return on equity | 9.33% | |
Regulatory equity ratio | 55.00% |
Contingencies and Regulatory 74
Contingencies and Regulatory Matters - Textual - SO Regulatory Matters GAS (Details) - USD ($) | Jan. 31, 2018 | Jan. 29, 2018 | Jan. 01, 2018 | Dec. 21, 2017 | Jun. 30, 2017 | Feb. 21, 2017 | Aug. 31, 2016 | Dec. 31, 2017 | Jun. 01, 2018 | Jan. 11, 2018 |
SOUTHERN Co GAS | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Impairment of long-lived assets | $ 0 | |||||||||
Atlanta Gas Light | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Public utilities, approved rate increase (decrease), amount | $ 34,000,000 | $ 13,000,000 | $ 20,000,000 | |||||||
Public utilities, approved rate increase (decrease) amount recovery of investments | $ 13,000,000 | |||||||||
Public utilities, approved return on equity | 9.50% | 9.60% | 10.75% | |||||||
Atlanta Gas Light | Minimum | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Public utilities, approved return on equity | 9.00% | 10.55% | ||||||||
Atlanta Gas Light | Maximum | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Public utilities, approved return on equity | 10.00% | 10.95% | ||||||||
Infrastructure Program | SOUTHERN Co GAS | Minimum | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Program duration period | 9 years | |||||||||
Infrastructure Program | SOUTHERN Co GAS | Maximum | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Program duration period | 10 years | |||||||||
energySMART [Member] | Nicor Gas | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Program duration period | 4 years | |||||||||
Subsequent Event | Atlanta Gas Light | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Public utilities, approved rate increase (decrease), amount | $ 137,000,000 | |||||||||
Public utilities, approved rate increase (decrease) amount recovery of investments | $ 93,000,000 | |||||||||
Public utilities, approved return on equity | 9.80% | |||||||||
Subsequent Event | Florida City Gas | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Tax Cuts and Jobs Acts of 2017, loss contingency, Damages Sought, reduction in base rate revenues, value | $ 4,000,000 | |||||||||
Subsequent Event | energySMART [Member] | Nicor Gas | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Program duration period | 4 years | |||||||||
i-SRP | STRIDE | Atlanta Gas Light | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Program duration period | 4 years | |||||||||
Infrastructure replacement program, petitioned investment amount (more than) | $ 177,000,000 | |||||||||
Scenario, Forecast | Atlanta Gas Light Company | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Annual base rate adjustment, increase in base rate revenues | $ 22,000,000 | |||||||||
Other Regulatory Liabilities [Member] | Subsequent Event | GEORGIA POWER CO | ||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||
Customer Refund Liability, Noncurrent | $ 188,000,000 |
Contingencies and Regulatory 75
Contingencies and Regulatory Matters - Textual - SO Kemper (Details) $ in Millions | Feb. 07, 2018 | Feb. 06, 2018USD ($) | Jun. 28, 2017USD ($) | Aug. 17, 2016USD ($) | Jun. 09, 2016USD ($) | Dec. 03, 2015USD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2017USD ($)mi | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)mi | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)miMW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2012USD ($) | Dec. 31, 2010USD ($) | May 31, 2017USD ($) | Jun. 17, 2016USD ($) | May 03, 2016USD ($) |
MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Plant capacity under coal gasification combined cycle technology | MW | 582 | ||||||||||||||||||||||||
Co two pipeline infrastructure | mi | 61 | 61 | 61 | ||||||||||||||||||||||
Maximum cap construction costs | $ 2,880 | ||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 18 | $ 22 | |||||||||||||||||||||||
PSC retail increase (decrease) | $ (8) | $ (2) | |||||||||||||||||||||||
Kemper IGCC | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Pre-Tax charge to income | $ 208 | $ 34 | $ 3,000 | $ 108 | $ 206 | $ 88 | $ 81 | $ 53 | |||||||||||||||||
After tax charge to income | 185 | 21 | 2,100 | 67 | 127 | 54 | 50 | 33 | $ 2,400 | $ 264 | $ 226 | ||||||||||||||
Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Maximum cap construction costs | $ 5,950 | $ 2,400 | |||||||||||||||||||||||
Cost cap exceptions | $ 570 | ||||||||||||||||||||||||
Period of commercial operations established by discovery docket | 5 years | ||||||||||||||||||||||||
Estimated cost | 7,380 | ||||||||||||||||||||||||
Cost related to grant funding | 137 | ||||||||||||||||||||||||
Pre-Tax charge to income | 2,800 | 208 | 34 | 3,000 | 108 | 206 | 88 | 81 | 53 | $ 242 | $ 3,070 | ||||||||||||||
After tax charge to income | $ 2,000 | 185 | $ 21 | $ 2,100 | $ 67 | $ 127 | $ 54 | $ 50 | $ 33 | 206 | $ 1,890 | ||||||||||||||
Reduction in customer rates annually | 26.8 | ||||||||||||||||||||||||
After tax charge to income, cost during suspension period | 164 | ||||||||||||||||||||||||
Amortization of regulatory assets | 8 years | ||||||||||||||||||||||||
Amortization of regulatory liabilities | 6 years | ||||||||||||||||||||||||
Disallowance pre-tax charge to income | 78 | ||||||||||||||||||||||||
Pre-tax charge to income before accumulated depreciation | 85 | ||||||||||||||||||||||||
Pre-Tax charge to income, accumulated depreciation | 7 | ||||||||||||||||||||||||
Disallowance after tax charge to income | 48 | ||||||||||||||||||||||||
Regulatory asset | 114 | 114 | $ 114 | ||||||||||||||||||||||
Regulatory liabilities | $ 26 | $ 26 | $ 26 | ||||||||||||||||||||||
Mine | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Term of management fee contract | 40 years | ||||||||||||||||||||||||
Scenario, Forecast | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 13 | ||||||||||||||||||||||||
Minimum | Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Pre-Tax charge to income | 50 | ||||||||||||||||||||||||
Maximum | Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Pre-Tax charge to income | $ 100 | ||||||||||||||||||||||||
In-Service Asset Proposal | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Public utilities, approved return on equity | 9.225% | ||||||||||||||||||||||||
PSC retail increase (decrease) | $ 126 | ||||||||||||||||||||||||
Public utilities approved equity capital structure percentage | 49.733% | ||||||||||||||||||||||||
In-Service Asset Proposal | Minimum | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Amortization period of regulatory assets and liabilities | 2 years | ||||||||||||||||||||||||
In-Service Asset Proposal | Maximum | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Amortization period of regulatory assets and liabilities | 10 years | ||||||||||||||||||||||||
Pending Litigation | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Loss contingency, damages sought, value | $ 500 | $ 100 | |||||||||||||||||||||||
Subsequent Event | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Public utilities, approved return on equity | 9.33% | ||||||||||||||||||||||||
Subsequent Event | Kemper IGCC | MISSISSIPPI POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 99.3 | ||||||||||||||||||||||||
Public utilities, approved return on equity | 8.60% |
Contingencies and Regulatory 76
Contingencies and Regulatory Matters - Textual - SO Nuclear Construction (Details) | Jan. 01, 2021 | Jan. 01, 2020 | Feb. 28, 2018USD ($) | Jan. 30, 2018USD ($) | Jan. 11, 2018USD ($) | Dec. 08, 2017payment | Jun. 09, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 20, 2016USD ($) | Jan. 01, 2016 | Feb. 20, 2014USD ($) | Sep. 30, 2018USD ($)installment | Sep. 30, 2017USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2009USD ($)utilityMW | Dec. 31, 2022USD ($) | Dec. 31, 2020USD ($) | Jun. 30, 2016USD ($) | Sep. 28, 2017USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2013 | Jan. 01, 2013 |
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Construction work in progress | $ 8,977,000,000 | $ 6,904,000,000 | $ 8,977,000,000 | ||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 8,145,000,000 | ||||||||||||||||||||||||
GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Number of construction units approved | utility | 2 | ||||||||||||||||||||||||
Electric generating capacity in mega watts under construction agreement | MW | 1,100 | ||||||||||||||||||||||||
Construction work in progress | 4,939,000,000 | 4,613,000,000 | 4,939,000,000 | ||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,750,000,000 | ||||||||||||||||||||||||
Maximum guarantee | $ 43,000,000 | ||||||||||||||||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||||||||||||||||
Return on equity, potential decrease each month percentage | 10.00% | ||||||||||||||||||||||||
Eligible project costs to be reimbursed | $ 3,460,000,000 | ||||||||||||||||||||||||
GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 920,000,000 | ||||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Maximum guarantee | $ 3,680,000,000 | ||||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Percent ownership | 45.70% | ||||||||||||||||||||||||
Cost settlement agreement revised forecast | $ 8,800,000,000 | ||||||||||||||||||||||||
Project capital cost forecast | 7,300,000,000 | ||||||||||||||||||||||||
Construction work in progress | 3,300,000,000 | ||||||||||||||||||||||||
Construction financing costs | 1,600,000,000 | ||||||||||||||||||||||||
Maximum guarantee | $ 1,700,000,000 | ||||||||||||||||||||||||
Number of payments made | payment | 3 | ||||||||||||||||||||||||
Ownership interest percentage required for voting for continuing construction | 90.00% | ||||||||||||||||||||||||
Increase (decrease) in construction budget | $ 1,000,000,000 | ||||||||||||||||||||||||
Public utilities extension project schedule term | 1 year | ||||||||||||||||||||||||
Percentage of approval required to change primary construction contractor | 90.00% | ||||||||||||||||||||||||
Percentage of approval required for material amendments | 67.00% | ||||||||||||||||||||||||
Estimated in-service capital cost | $ 4,418,000,000 | ||||||||||||||||||||||||
Additional construction capital costs | $ 3,300,000,000 | $ 4,400,000,000 | |||||||||||||||||||||||
Construction In progress, before payments | 4,800,000,000 | ||||||||||||||||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||||||||||||||||
Public utilities, approved return on equity | 10.00% | ||||||||||||||||||||||||
Return on equity reduction, negative impact on earnings | 25,000,000 | 20,000,000 | |||||||||||||||||||||||
Production tax credit amount per unit net present value | 500,000,000 | ||||||||||||||||||||||||
Scenario, Forecast | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Customer refund | $ 44,000,000 | ||||||||||||||||||||||||
Scenario, Forecast | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Construction financing costs | $ 3,100,000,000 | ||||||||||||||||||||||||
Customer refunds, number of installments | installment | 3 | ||||||||||||||||||||||||
Customer refunds, amount per customer | $ 25 | ||||||||||||||||||||||||
Additional construction capital costs | $ 450,000,000 | ||||||||||||||||||||||||
Amendment to estimated in-service capital cost | $ 5,680,000,000 | ||||||||||||||||||||||||
Public utilities, approved return on equity | 5.30% | 8.30% | |||||||||||||||||||||||
Return on equity reduction, negative impact on earnings | $ 120,000,000 | $ 585,000,000 | |||||||||||||||||||||||
FFB Loan | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 2,600,000,000 | $ 2,600,000,000 | $ 2,600,000,000 | ||||||||||||||||||||||
Loan Guarantee Agreement | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Credit facility conditional borrowing commitment | $ 1,670,000,000 | ||||||||||||||||||||||||
Subsequent Event | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Increase (decrease) in tariff | $ 50,000,000 | ||||||||||||||||||||||||
Customer refund | $ 188,000,000 | ||||||||||||||||||||||||
Additional construction capital costs | $ 542,000,000 | ||||||||||||||||||||||||
Vogtle Owners [Member] | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Loss Contingencies [Line Items] | |||||||||||||||||||||||||
Period of notice required in the event letters of credit are not renewed | 30 days |
Contingencies and Regulatory 77
Contingencies and Regulatory Matters - Table - SO Nuclear Construction (Details) - GEORGIA POWER CO - Plant Vogtle Units 3 And 4 $ in Billions | Dec. 31, 2017USD ($) |
Other Commitments [Line Items] | |
Project capital cost forecast | $ 7.3 |
Net investment as of December 31, 2017 | 3.4 |
Remaining estimate to complete | $ 3.9 |
Contingencies and Regulatory 78
Contingencies and Regulatory Matters - Textual - SO Other Matters (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Property, plant and equipment | $ 79,872,000,000 | $ 78,446,000,000 |
Natural Gas Storage - Salt Dome Caverns | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Property, plant and equipment | $ 112,000,000 | |
Property, Plant and Equipment | Natural Gas Storage - Salt Dome Caverns | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Concentration risk (as percent) | 20.00% | |
SOUTHERN Co GAS | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Property, plant and equipment | $ 11,728,000,000 | $ 10,565,000,000 |
Impairment of long-lived assets | $ 0 |
Contingencies and Regulatory 79
Contingencies and Regulatory Matters - Textual - APC (Details) - ALABAMA POWER CO | 1 Months Ended | 12 Months Ended | ||||
Apr. 30, 2016MW | Dec. 31, 2017USD ($) | Dec. 31, 2015USD ($)MW | Feb. 17, 2017USD ($) | Jan. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Claims awarded to companies related to nuclear fuel disposal litigation | $ 26,000,000 | |||||
Adjusting point of weighted cost of equity | 5.98% | |||||
Percent of basis points | 0.07% | |||||
Rate adjustment period | 2 years | |||||
Maximum percentage of rate RSE | 4.00% | |||||
Maximum annual percentage of ratio R\rate | 5.00% | |||||
Rate RSE refund liability | $ 73,000,000 | |||||
Rate RSE increase | 4.48% | |||||
Rate RSE increase amount | $ 245,000,000 | |||||
Tax cuts and jobs act, anticipated retail revenue reduction, next twelve months | $ 250,000,000 | |||||
Under recovered certified power purchase agreements | 12,000,000 | 142,000,000 | ||||
Over (under) recovered environmental clause | 17,000,000 | 9,000,000 | ||||
Over recovered fuel cost | 25,000,000 | $ 76,000,000 | ||||
Minimum natural disaster reserve balance, triggering establishment charge | 50,000,000 | |||||
Natural disaster reserve, expected collection annually until reserve is restored | 16,000,000 | |||||
Natural disaster reserve authorized limit | $ 75,000,000 | |||||
Maximum period for recovery deferred stock related operations and maintenance costs and any future reserve deficits | 24 months | |||||
Maximum rate NDR charge per month, monthly nonresidential customer account | $ 10 | |||||
Maximum rate NDR charge per month, monthly residential customer account | 5 | |||||
Natural disaster reserve | $ 38,000,000 | |||||
Minimum | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Weighted cost of equity | 5.75% | |||||
Potential period for next depreciation study | 2 years | |||||
Maximum | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Weighted cost of equity | 6.21% | |||||
Potential period for next depreciation study | 4 years | |||||
Regulatory Assets [Member] | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Under recovered certified power purchase agreements | $ 69,000,000 | |||||
Over (under) recovered environmental clause | $ (36,000,000) | |||||
Plant Gorgas Units 6 and 7 | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Capacity of units included in request for decertification of units | MW | 200 | |||||
Plant Barry Unit 3 | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Capacity of units included in request for decertification of units | MW | 225 | |||||
Plant Barry Units 1 And 2 | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Capacity of units included in request for decertification of units | MW | 250 | |||||
Plant Greene County Units 1 And 2 | ||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||
Capacity of units included in request for decertification of units | MW | 300 |
Contingencies and Regulatory 80
Contingencies and Regulatory Matters - Textual - GPC - Contingencies and Regulatory Matters (Details) | Jan. 01, 2021 | Jan. 01, 2020 | Feb. 28, 2018USD ($) | Jan. 30, 2018USD ($) | Jan. 11, 2018USD ($) | Dec. 08, 2017payment | Jun. 09, 2017 | Dec. 20, 2016USD ($) | Jan. 01, 2016USD ($) | Jan. 01, 2013 | Jul. 31, 2016MW | Sep. 30, 2018USD ($)installment | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)MW | Dec. 31, 2015USD ($) | Dec. 31, 2009utility | Dec. 31, 2022 | Jun. 30, 2016USD ($) | Jun. 30, 2019USD ($) | Dec. 31, 2016USD ($) | Aug. 31, 2016 | May 01, 2016USD ($) | Dec. 31, 2013 |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Net regulatory assets | $ (1,894,000,000) | $ 5,866,000,000 | |||||||||||||||||||||
GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Number of construction units approved | utility | 2 | ||||||||||||||||||||||
Environmental exit costs, assets previously disposed, liability for remediation | $ 22,000,000 | 17,000,000 | |||||||||||||||||||||
Claims awarded to companies related to nuclear fuel disposal litigation | $ 18,000,000 | ||||||||||||||||||||||
Increase (decrease) in base tariff rate | $ 49,000,000 | ||||||||||||||||||||||
Increase (decrease) in ECCR tariff | 75,000,000 | ||||||||||||||||||||||
Increase (decrease) in demand side management tariff | 3,000,000 | ||||||||||||||||||||||
Increase (decrease) in municipal franchise fee tariff | 13,000,000 | ||||||||||||||||||||||
Increase (decrease) in revenue to be received from base rate change | $ 140,000,000 | ||||||||||||||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||||||||||||||
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% | ||||||||||||||||||||||
Capacity of units included in application request by subsidiaries for future period requests | MW | 1,200 | ||||||||||||||||||||||
Capacity of renewable resources approved for self-build | MW | 200 | ||||||||||||||||||||||
Approved capacity of units for solar generation resources | MW | 510 | ||||||||||||||||||||||
Approved increase (decrease) in annual billing based on fuel cost recovery rate | $ (350,000,000) | $ (313,000,000) | |||||||||||||||||||||
Adjustment to fuel cost recovery rate if under recovered fuel balance exceeds budget thereafter | $ 200,000,000 | ||||||||||||||||||||||
Required period for options and hedges | 48 months | ||||||||||||||||||||||
Over recovered fuel balance | $ 165,000,000 | 84,000,000 | |||||||||||||||||||||
Accrual under alternate rate plan | 30,000,000 | ||||||||||||||||||||||
Net regulatory assets | $ 232,000,000 | 3,506,000,000 | |||||||||||||||||||||
Scenario, Forecast | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Customer refund | $ 44,000,000 | ||||||||||||||||||||||
Scenario, Forecast | Georgia Power And Atlanta Gas Light Company | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Percentage basis net merger savings | 40.00% | ||||||||||||||||||||||
Customers | Scenario, Forecast | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Percentage basis net merger savings | 60.00% | ||||||||||||||||||||||
Minimum | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Retail rate of return on common equity | 10.00% | ||||||||||||||||||||||
Maximum | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Retail rate of return on common equity | 12.00% | ||||||||||||||||||||||
Capacity of renewable resources considered for renewable commercial and industrial program | MW | 200 | ||||||||||||||||||||||
Maximum | Scenario, Forecast | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Cost recovery, new nuclear | $ 99,000,000 | ||||||||||||||||||||||
Cost recovery, estimate, nuclear fuel | $ 50,000,000 | ||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Number of payments made | payment | 3 | ||||||||||||||||||||||
Additional construction capital costs | $ 3,300,000,000 | $ 4,400,000,000 | |||||||||||||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||||||||||||||
Percent ownership | 45.70% | ||||||||||||||||||||||
Cost settlement agreement revised forecast | $ 8,800,000,000 | ||||||||||||||||||||||
Project capital cost forecast | 7,300,000,000 | ||||||||||||||||||||||
Public utilities, approved return on equity | 10.00% | ||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | Scenario, Forecast | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Additional construction capital costs | $ 450,000,000 | ||||||||||||||||||||||
Customer refunds, number of installments | installment | 3 | ||||||||||||||||||||||
Public utilities, approved return on equity | 5.30% | 8.30% | |||||||||||||||||||||
Customer refunds, amount per customer | $ 25 | ||||||||||||||||||||||
Plant Mitchell Units 3, 4A, and 4B | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Capacity of units included in request for decertification of units | MW | 217 | ||||||||||||||||||||||
Plant Kraft Unit 1 | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Capacity of units included in request for decertification of units | MW | 17 | ||||||||||||||||||||||
Intercession City Combustion Turbine | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Capacity of units included in request to sell | MW | 143 | ||||||||||||||||||||||
Percent ownership | 33.00% | ||||||||||||||||||||||
Storm damage reserves | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Incremental restoration costs | 260,000,000 | ||||||||||||||||||||||
Net regulatory assets | $ 333,000,000 | $ 206,000,000 | |||||||||||||||||||||
Vogtle Owners [Member] | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Period of notice required in the event letters of credit are not renewed | 30 days | ||||||||||||||||||||||
Subsequent Event | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||
Additional construction capital costs | $ 542,000,000 | ||||||||||||||||||||||
Increase (decrease) in tariff | $ 50,000,000 | ||||||||||||||||||||||
Customer refund | $ 188,000,000 |
Contingencies and Regulatory 81
Contingencies and Regulatory Matters - Textual - GPC Nuclear Construction (Details) | Jan. 01, 2021 | Jan. 01, 2020 | Feb. 28, 2018USD ($) | Jan. 30, 2018USD ($) | Jan. 11, 2018USD ($) | Dec. 08, 2017payment | Jun. 09, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 20, 2016USD ($) | Jan. 01, 2016 | Feb. 20, 2014USD ($) | Sep. 30, 2018USD ($)installment | Sep. 30, 2017USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2009USD ($)utilityMW | Dec. 31, 2022USD ($) | Dec. 31, 2020USD ($) | Jun. 30, 2016USD ($) | Sep. 28, 2017USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2013 | Jan. 01, 2013 |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Construction work in progress | $ 8,977,000,000 | $ 6,904,000,000 | $ 8,977,000,000 | ||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 8,145,000,000 | ||||||||||||||||||||||||
GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Number of construction units approved | utility | 2 | ||||||||||||||||||||||||
Electric generating capacity in mega watts under construction agreement | MW | 1,100 | ||||||||||||||||||||||||
Construction work in progress | 4,939,000,000 | 4,613,000,000 | 4,939,000,000 | ||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,750,000,000 | ||||||||||||||||||||||||
Maximum guarantee | $ 43,000,000 | ||||||||||||||||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||||||||||||||||
Return on equity, potential decrease each month percentage | 10.00% | ||||||||||||||||||||||||
Eligible project costs to be reimbursed | $ 3,460,000,000 | ||||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Maximum guarantee | $ 3,680,000,000 | ||||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Percent ownership | 45.70% | ||||||||||||||||||||||||
Cost settlement agreement revised forecast | $ 8,800,000,000 | ||||||||||||||||||||||||
Project capital cost forecast | 7,300,000,000 | ||||||||||||||||||||||||
Construction work in progress | 3,300,000,000 | ||||||||||||||||||||||||
Construction financing costs | 1,600,000,000 | ||||||||||||||||||||||||
Maximum guarantee | $ 1,700,000,000 | ||||||||||||||||||||||||
Number of payments made | payment | 3 | ||||||||||||||||||||||||
Ownership interest percentage required for voting for continuing construction | 90.00% | ||||||||||||||||||||||||
Increase (decrease) in construction budget | $ 1,000,000,000 | ||||||||||||||||||||||||
Public utilities extension project schedule term | 1 year | ||||||||||||||||||||||||
Percentage of approval required to change primary construction contractor | 90.00% | ||||||||||||||||||||||||
Percentage of approval required for material amendments | 67.00% | ||||||||||||||||||||||||
Estimated in-service capital cost | $ 4,418,000,000 | ||||||||||||||||||||||||
Additional construction capital costs | $ 3,300,000,000 | $ 4,400,000,000 | |||||||||||||||||||||||
Construction In progress, before payments | 4,800,000,000 | ||||||||||||||||||||||||
Retail rate of return on common equity | 10.95% | ||||||||||||||||||||||||
Public utilities, approved return on equity | 10.00% | ||||||||||||||||||||||||
Return on equity reduction, negative impact on earnings | 25,000,000 | 20,000,000 | |||||||||||||||||||||||
Production tax credit amount per unit net present value | 500,000,000 | ||||||||||||||||||||||||
Scenario, Forecast | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Customer refund | $ 44,000,000 | ||||||||||||||||||||||||
Scenario, Forecast | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Construction financing costs | $ 3,100,000,000 | ||||||||||||||||||||||||
Customer refunds, number of installments | installment | 3 | ||||||||||||||||||||||||
Customer refunds, amount per customer | $ 25 | ||||||||||||||||||||||||
Additional construction capital costs | $ 450,000,000 | ||||||||||||||||||||||||
Amendment to estimated in-service capital cost | $ 5,680,000,000 | ||||||||||||||||||||||||
Public utilities, approved return on equity | 5.30% | 8.30% | |||||||||||||||||||||||
Return on equity reduction, negative impact on earnings | $ 120,000,000 | $ 585,000,000 | |||||||||||||||||||||||
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 920,000,000 | ||||||||||||||||||||||||
Vogtle Owners [Member] | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Period of notice required in the event letters of credit are not renewed | 30 days | ||||||||||||||||||||||||
Subsequent Event | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Increase (decrease) in tariff | $ 50,000,000 | ||||||||||||||||||||||||
Customer refund | $ 188,000,000 | ||||||||||||||||||||||||
Additional construction capital costs | $ 542,000,000 | ||||||||||||||||||||||||
FFB Loan | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 2,600,000,000 | $ 2,600,000,000 | $ 2,600,000,000 | ||||||||||||||||||||||
Loan Guarantee Agreement | GEORGIA POWER CO | |||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||||||
Credit facility conditional borrowing commitment | $ 1,670,000,000 |
Contingencies and Regulatory 82
Contingencies and Regulatory Matters - Table - GPC Nuclear Construction - Cost and Schedule (Details) - Plant Vogtle Units 3 And 4 - GEORGIA POWER CO $ in Billions | Dec. 31, 2017USD ($) |
Commitments [Line Items] | |
Cost settlement agreement revised forecast, net of payments | $ 7.3 |
Net investment as of December 31, 2017 | 3.4 |
Remaining estimate to complete | $ 3.9 |
Contingencies and Regulatory 83
Contingencies and Regulatory Matters - Textual - GULF (Details) | Jan. 01, 2018MW | Jul. 01, 2017 | Apr. 04, 2017intervenor | Jan. 31, 2018USD ($) | Mar. 31, 2017USD ($)MW | Jun. 30, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2019USD ($) | Aug. 29, 2016USD ($) |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Other cost of removal obligations | $ 2,684,000,000 | $ 2,748,000,000 | |||||||||||
GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Environmental exit costs, assets previously disposed, liability for remediation | 52,000,000 | 44,000,000 | |||||||||||
Other cost of removal obligations | 221,000,000 | 249,000,000 | |||||||||||
Reduction in depreciation expense | $ 34,000,000 | 0 | $ 20,100,000 | $ 8,400,000 | |||||||||
Retail rate of return on common equity | 10.25% | ||||||||||||
Retail regulatory equity ratio | 0.525 | ||||||||||||
Loss on Plant Scherer Unit 3 | $ 33,000,000 | 0 | 0 | ||||||||||
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 | ||||||||||||
Regulatory asset | $ 63,000,000 | ||||||||||||
Regulatory asset deferral period | 15 years | ||||||||||||
Under Recovered Regulatory Clause Revenues and Other Current Liabilities | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Environmental exit costs, assets previously disposed, liability for remediation | $ 5,000,000 | 4,000,000 | |||||||||||
Other regulatory assets, deferred and other deferred credits and liabilities | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Environmental exit costs, assets previously disposed, liability for remediation | 47,000,000 | 40,000,000 | |||||||||||
Other regulatory liabilities current | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Over (under) recovered fuel balance | (22,000,000) | 15,000,000 | |||||||||||
Over recovered energy conservation costs | 4,000,000 | ||||||||||||
Under recovered regulatory clause revenues | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Over (under) recovered fuel balance | (2,000,000) | ||||||||||||
Over (under) recovered environmental cost | $ 11,000,000 | $ 8,000,000 | $ 0 | ||||||||||
Settlement Agreement | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Other cost of removal obligations | $ 62,500,000 | ||||||||||||
Scenario, Forecast | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Increase retail base rate, net customer impact | $ 54,300,000 | ||||||||||||
Increase retail base rate, annual base revenue | 62,000,000 | ||||||||||||
Increase retail base rate, cost recovery credit | $ 8,000,000 | ||||||||||||
Retail regulatory equity ratio | 0.535 | ||||||||||||
Rate case settlement annual reduction base rates | $ 18,200,000 | ||||||||||||
Rate case settlement annual reduction environmental cost recovery rate | 15,600,000 | ||||||||||||
Tax reform settlement refund | $ 69,400,000 | ||||||||||||
Minimum | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Retail rate of return on common equity | 9.25% | ||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | ||||||||||||
Maximum | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Retail rate of return on common equity | 11.25% | ||||||||||||
Plant Scherer Unit 3 [Member] | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Number of Intervenors | intervenor | 3 | ||||||||||||
Loss on Plant Scherer Unit 3 | $ 32,500,000 | ||||||||||||
Plant Smith Units 1 and 2 | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Capacity of units written down | MW | 205 | ||||||||||||
Subsequent Event | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 63,000,000 | ||||||||||||
Subsequent Event | Plant Smith Units 1 and 2 | GULF POWER CO | |||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||
Capacity of units approved for decertification | MW | 357 | ||||||||||||
Capacity of units approved for decertification, amortization period | 15 years |
Contingencies and Regulatory 84
Contingencies and Regulatory Matters - Textual - MPC (Details) | Feb. 14, 2018USD ($) | Feb. 07, 2018USD ($) | Feb. 06, 2018USD ($) | Jan. 01, 2018USD ($) | Sep. 28, 2017MW | Sep. 18, 2017 | Jun. 28, 2017USD ($) | May 04, 2017 | Jan. 12, 2017USD ($) | Aug. 17, 2016USD ($) | Jun. 09, 2016USD ($) | May 01, 2016USD ($) | Mar. 31, 2016 | Dec. 03, 2015USD ($) | Jun. 30, 2017USD ($) | Jul. 31, 2016USD ($) | Mar. 15, 2017USD ($) | Dec. 31, 2017USD ($)mi | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)mi | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)rate_plan_filingmiMW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2013USD ($)Customer | Dec. 31, 2012USD ($) | Dec. 31, 2011 | Dec. 31, 2010USD ($) | Dec. 31, 2008MW | May 31, 2017USD ($) | Feb. 01, 2018USD ($) | Jan. 26, 2018day | Feb. 03, 2017USD ($) | Jan. 21, 2017USD ($) | Jun. 17, 2016USD ($) | May 03, 2016USD ($) | Feb. 29, 2016USD ($) | Dec. 31, 2014MW |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Storm restoration costs | $ 9,000,000 | |||||||||||||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) Cash Collateral from Counterparties | $ 0 | |||||||||||||||||||||||||||||||||||||||||||
Increase in base rate under cost based electric tariff due to settlement | $ 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||
AFUDC cost | $ 22,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Period of notice to cancel counterparty | 10 years | |||||||||||||||||||||||||||||||||||||||||||
Period of notice required for contract termination | 1 year | |||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 18,000,000 | $ 22,000,000 | ||||||||||||||||||||||||||||||||||||||||||
Percentage of PSC retail rate incrase | 0.85% | |||||||||||||||||||||||||||||||||||||||||||
Energy power supply agreement term | 10 years | 10 years | ||||||||||||||||||||||||||||||||||||||||||
Energy power supply agreement capacity | MW | 286 | 86 | 152 | |||||||||||||||||||||||||||||||||||||||||
Performance evaluation plan, number of filings per calendar year | rate_plan_filing | 2 | |||||||||||||||||||||||||||||||||||||||||||
Annual PEP lookback refund to customers | $ 5,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Annual PEP filing rate increase | 1.90% | |||||||||||||||||||||||||||||||||||||||||||
Annual PEP filing rate increase amount | $ 15,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Anticipates of elimination adjustment will result in additional revenue | $ 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Gain contingency, surcharge revenue | $ 5,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Required customers for energy efficiency programs | Customer | 25,000 | |||||||||||||||||||||||||||||||||||||||||||
PSC retail increase (decrease) | $ (8,000,000) | $ (2,000,000) | ||||||||||||||||||||||||||||||||||||||||||
Regulatory amortization period | 5 years | |||||||||||||||||||||||||||||||||||||||||||
Psc approved annual property damage reserve accrual | $ 1,000,000 | $ 3,000,000 | ||||||||||||||||||||||||||||||||||||||||||
Plant capacity under coal gasification combined cycle technology | MW | 582 | |||||||||||||||||||||||||||||||||||||||||||
Co two pipeline infrastructure | mi | 61 | 61 | 61 | |||||||||||||||||||||||||||||||||||||||||
Maximum cap construction costs | $ 2,880,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Kemper IGCC | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax charge to income | $ 208,000,000 | $ 34,000,000 | $ 3,000,000,000 | $ 108,000,000 | $ 206,000,000 | $ 88,000,000 | $ 81,000,000 | $ 53,000,000 | ||||||||||||||||||||||||||||||||||||
After tax charge to income | 185,000,000 | 21,000,000 | 2,100,000,000 | 67,000,000 | 127,000,000 | 54,000,000 | 50,000,000 | 33,000,000 | $ 2,400,000,000 | 264,000,000 | $ 226,000,000 | |||||||||||||||||||||||||||||||||
Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Period of amortization of regulatory assets | 36 months | |||||||||||||||||||||||||||||||||||||||||||
Regulatory asset | 114,000,000 | $ 114,000,000 | 114,000,000 | |||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 26,000,000 | 26,000,000 | $ 26,000,000 | |||||||||||||||||||||||||||||||||||||||||
Maximum cap construction costs | $ 5,950,000,000 | $ 2,400,000,000 | ||||||||||||||||||||||||||||||||||||||||||
Cost cap exceptions | $ 570,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Period of commercial operations established by discovery docket | 5 years | |||||||||||||||||||||||||||||||||||||||||||
Estimated cost | 7,380,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Cost related to grant funding | 137,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Pre-Tax charge to income | 2,800,000,000 | 208,000,000 | 34,000,000 | 3,000,000,000 | 108,000,000 | 206,000,000 | 88,000,000 | 81,000,000 | 53,000,000 | 242,000,000 | $ 3,070,000,000 | |||||||||||||||||||||||||||||||||
After tax charge to income | $ 2,000,000,000 | 185,000,000 | $ 21,000,000 | $ 2,100,000,000 | $ 67,000,000 | 127,000,000 | $ 54,000,000 | $ 50,000,000 | $ 33,000,000 | 206,000,000 | $ 1,890,000,000 | |||||||||||||||||||||||||||||||||
After tax charge to income, cost during suspension period | 164,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Amortization of regulatory assets | 8 years | |||||||||||||||||||||||||||||||||||||||||||
Amortization of regulatory liabilities | 6 years | |||||||||||||||||||||||||||||||||||||||||||
Disallowance pre-tax charge to income | 78,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Pre-tax charge to income before accumulated depreciation | 85,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Pre-Tax charge to income, accumulated depreciation | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Disallowance after tax charge to income | 48,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Reduction in customer rates annually | 26,800,000 | |||||||||||||||||||||||||||||||||||||||||||
Mine | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Term of management fee contract | 40 years | |||||||||||||||||||||||||||||||||||||||||||
Plant Sweatt Units 1 And 2 | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Capacity unit conversation to non-fossil fuel source | MW | 80 | |||||||||||||||||||||||||||||||||||||||||||
Plant Watson Units 4 And 5 | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Capacity unit conversation to non-fossil fuel source | MW | 750 | |||||||||||||||||||||||||||||||||||||||||||
Plant Greene County Units 1 And 2 | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Capacity unit conversation to non-fossil fuel source | MW | 200 | |||||||||||||||||||||||||||||||||||||||||||
Regulatory asset | 17,000,000 | 17,000,000 | $ 17,000,000 | |||||||||||||||||||||||||||||||||||||||||
Plant Watson | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Regulatory asset | $ 41,000,000 | |||||||||||||||||||||||||||||||||||||||||||
MRA Revenue | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 13,000,000 | 13,000,000 | ||||||||||||||||||||||||||||||||||||||||||
Retail | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | $ 37,000,000 | $ 37,000,000 | ||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 55,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Approved increase (decrease) in annual billing based on fuel cost recovery rate | $ (39,000,000) | |||||||||||||||||||||||||||||||||||||||||||
Under recovered fuel cost | $ 6,000,000 | $ 6,000,000 | $ 6,000,000 | |||||||||||||||||||||||||||||||||||||||||
Subsequent Event | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Number of days to file information on impact of tax reform legislation | day | 30 | |||||||||||||||||||||||||||||||||||||||||||
Annual PEP filing rate increase amount | $ 26,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved return on equity | 9.33% | |||||||||||||||||||||||||||||||||||||||||||
Regulatory equity ratio | 55.00% | |||||||||||||||||||||||||||||||||||||||||||
Requested increase in property damage reserve accrual | $ 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Subsequent Event | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 99,300,000 | |||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved return on equity | 8.60% | |||||||||||||||||||||||||||||||||||||||||||
Subsequent Event | MRA Revenue | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 11,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Scenario, Forecast | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 13,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Annual PEP filing rate increase | 4.00% | |||||||||||||||||||||||||||||||||||||||||||
Annual PEP filing rate increase amount | $ 38,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Scenario, Forecast | Subsequent Event | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities requested revenue requirement increase (decrease) | 26,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Plant Daniel Units 1 & 2 (coal) | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | |||||||||||||||||||||||||||||||||||||||||
Maximum | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities approved rate increase (decrease) | 2.00% | 2.00% | ||||||||||||||||||||||||||||||||||||||||||
Maximum | Subsequent Event | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities, requested rate increase (decrease) | 2.00% | |||||||||||||||||||||||||||||||||||||||||||
Public utilities requested rate increase (decrease) | $ 17,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Maximum | Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax charge to income | 100,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Minimum | Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax charge to income | $ 50,000,000 | |||||||||||||||||||||||||||||||||||||||||||
In-Service Asset Proposal | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved return on equity | 9.225% | |||||||||||||||||||||||||||||||||||||||||||
PSC retail increase (decrease) | $ 126,000,000 | |||||||||||||||||||||||||||||||||||||||||||
Public utilities approved equity capital structure percentage | 49.733% | |||||||||||||||||||||||||||||||||||||||||||
In-Service Asset Proposal | Maximum | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Amortization period of regulatory assets and liabilities | 10 years | |||||||||||||||||||||||||||||||||||||||||||
In-Service Asset Proposal | Minimum | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Amortization period of regulatory assets and liabilities | 2 years | |||||||||||||||||||||||||||||||||||||||||||
Pending Litigation | Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||
Loss contingency, damages sought, value | $ 500,000,000 | $ 100,000,000 |
Contingencies and Regulatory 85
Contingencies and Regulatory Matters - Textual - SPC (Details) - RE Roserock, LLC - SOUTHERN POWER CO - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2015 | |
Loss Contingencies [Line Items] | ||
Percentage of voting interests acquired | 51.00% | |
Withholding of construction contract payments | $ 26 | $ 26 |
Contingencies and Regulatory 86
Contingencies and Regulatory Matters - Textual - Gas (Details) | Feb. 15, 2018USD ($) | Jan. 31, 2018USD ($) | Jan. 01, 2018USD ($) | Dec. 21, 2017USD ($) | Dec. 01, 2017USD ($) | Oct. 23, 2017USD ($) | Jun. 30, 2017USD ($) | Feb. 21, 2017USD ($) | Oct. 31, 2017USD ($) | Oct. 31, 2016USD ($) | Aug. 31, 2016USD ($) | Mar. 31, 2016USD ($)mi | Oct. 31, 2015USD ($) | Dec. 31, 2017USD ($)stateutilitydefendantsitecavernpipelinemi | Dec. 31, 2015USD ($)stationmi | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | Dec. 31, 2017USD ($)stateutilitysitecavern | Dec. 31, 2016USD ($) | Feb. 28, 2015USD ($) |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Property, plant and equipment | $ 79,872,000,000 | $ 79,872,000,000 | $ 78,446,000,000 | ||||||||||||||||||
SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Number of states in which entity operates | state | 7 | 7 | |||||||||||||||||||
Number of natural gas distribution utilities | utility | 7 | 7 | |||||||||||||||||||
Environmental exit costs, costs accrued to date | $ 388,000,000 | $ 388,000,000 | 426,000,000 | ||||||||||||||||||
Property, plant and equipment | 11,728,000,000 | $ 11,728,000,000 | $ 10,565,000,000 | ||||||||||||||||||
Impairment of long-lived assets | 0 | ||||||||||||||||||||
Nicor Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Loss contingency, damages sought, value | $ 300,000 | ||||||||||||||||||||
Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Annual proceeds from strategic economic development projects | $ 15,000,000 | ||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 34,000,000 | $ 13,000,000 | $ 20,000,000 | ||||||||||||||||||
Public utilities, approved rate increase (decrease) amount recovery of investments | $ 13,000,000 | ||||||||||||||||||||
Public utilities, approved return on equity | 9.50% | 9.60% | 10.75% | ||||||||||||||||||
Reduction in depreciation expense | $ 3,000,000 | ||||||||||||||||||||
Public utilities requested rate increase (decrease) | $ 22,000,000 | ||||||||||||||||||||
Florida City Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Public utilities requested rate increase (decrease) | $ 19,000,000 | ||||||||||||||||||||
Public utilities, requested return on equity percentage | 11.25% | ||||||||||||||||||||
Regulated operation, allowable cost recovery | $ 3,000,000 | ||||||||||||||||||||
Public utilities, interim rate increase (decrease) amount | $ 5,000,000 | ||||||||||||||||||||
Pending Litigation | SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Number of states in which entity operates | state | 1 | 1 | |||||||||||||||||||
Number of natural gas distribution utilities | utility | 1 | 1 | |||||||||||||||||||
Loss contingency, number of defendants | defendant | 1 | ||||||||||||||||||||
Minimum | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Public utilities, approved return on equity | 9.00% | 10.55% | |||||||||||||||||||
Minimum | Pending Litigation | SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Loss contingency, estimate of possible loss | $ 11,000,000 | $ 11,000,000 | |||||||||||||||||||
Maximum | Nicor Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Infrastructure investment, annual customer rate increase | 4.00% | ||||||||||||||||||||
Infrastructure investment, annual customer rate increase in any given year | 5.50% | ||||||||||||||||||||
Maximum | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Public utilities, approved return on equity | 10.00% | 10.95% | |||||||||||||||||||
Manufactured Gas Plants [Member] | SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Number of states in which entity operates | state | 5 | 5 | |||||||||||||||||||
Number of sites | site | 46 | 46 | |||||||||||||||||||
Location One | SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Environmental exit costs, assets previously disposed, liability for remediation | $ 2,000,000 | $ 2,000,000 | |||||||||||||||||||
Regulatory Infrastructure Program | Nicor Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 9 years | ||||||||||||||||||||
AIR | Elizabethtown Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 4 years | ||||||||||||||||||||
Fair value inputs, discount rate | 6.65% | ||||||||||||||||||||
Approved infrastructure replacement program | $ 115,000,000 | ||||||||||||||||||||
Safety, Modernization and Reliability Tariff (SMART) Plan | Elizabethtown Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Infrastructure replacement program, petitioned investment amount (more than) | $ 1,100,000,000 | ||||||||||||||||||||
Regulated operations, natural gas pipeline length, considered for replacement | mi | 630 | ||||||||||||||||||||
Number of regulator stations, considered for replacement | station | 240 | ||||||||||||||||||||
SAVE | Virginia Natural Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 5 years | ||||||||||||||||||||
Regulated operations, natural gas pipeline length, approved for replacement | mi | 200 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, amount per year | $ 25,000,000 | ||||||||||||||||||||
Approved infrastructure replacement program | $ 105,000,000 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | Year 2016 | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, approved investment amount, current fiscal year | $ 30,000,000 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | Year 2017 | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, approved investment amount, current fiscal year | 35,000,000 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | Year 2018 | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, approved investment amount, current fiscal year | 35,000,000 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | Year 2019 | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, approved investment amount, current fiscal year | 35,000,000 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | Year 2020 | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, approved investment amount, current fiscal year | 35,000,000 | ||||||||||||||||||||
SAVE | Maximum | Virginia Natural Gas | Year 2021 | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program, approved investment amount, current fiscal year | $ 35,000,000 | ||||||||||||||||||||
SAFE | Florida City Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 10 years | ||||||||||||||||||||
Approved infrastructure replacement program | $ 105,000,000 | ||||||||||||||||||||
energySMART [Member] | Nicor Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 4 years | ||||||||||||||||||||
Approved infrastructure replacement program | $ 113,000,000 | ||||||||||||||||||||
Energy efficiency and term reduction expenditures | 107,000,000 | ||||||||||||||||||||
Midstream Operations | Gas pipeline | SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Number of gas construction projects | pipeline | 2 | ||||||||||||||||||||
i-SRP | STRIDE | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 4 years | ||||||||||||||||||||
Infrastructure replacement program, petitioned investment amount (more than) | $ 177,000,000 | ||||||||||||||||||||
Approved infrastructure replacement program | $ 445,000,000 | 445,000,000 | |||||||||||||||||||
i-CGP | STRIDE | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program | 91,000,000 | 91,000,000 | |||||||||||||||||||
i-VPR | STRIDE | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Approved infrastructure replacement program | $ 275,000,000 | 275,000,000 | |||||||||||||||||||
Regulated operations, natural gas pipeline length, approved for replacement | mi | 756 | ||||||||||||||||||||
Regulated operations, natural gas pipeline length, considered for replacement | mi | 3,300 | ||||||||||||||||||||
Favorable Regulatory Action | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Litigation settlement | 144,000,000 | ||||||||||||||||||||
Gain contingency, surcharge revenue | $ 15,000,000 | ||||||||||||||||||||
Gain contingency, surcharge revenue, annual increase | $ 15,000,000 | $ 15,000,000 | |||||||||||||||||||
Proceeds from legal settlements | $ 20,000,000 | ||||||||||||||||||||
True Up Recovery | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Gain contingency, unrecorded amount | 187,000,000 | 34,000,000 | 187,000,000 | $ 178,000,000 | |||||||||||||||||
Interest expense | 1,000,000 | ||||||||||||||||||||
Selling, general and administrative expense | $ 5,000,000 | ||||||||||||||||||||
True-Up Recovery, Unrecognized Equity | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Gain contingency, unrecorded amount | $ 104,000,000 | $ 104,000,000 | |||||||||||||||||||
Subsequent Event | SOUTHERN Co GAS | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Tax reform legislation, adjustment to base rate | $ 0 | ||||||||||||||||||||
Subsequent Event | Atlanta Gas Light | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Public utilities, approved rate increase (decrease), amount | $ 137,000,000 | ||||||||||||||||||||
Public utilities, approved rate increase (decrease) amount recovery of investments | $ 93,000,000 | ||||||||||||||||||||
Public utilities, approved return on equity | 9.80% | ||||||||||||||||||||
Subsequent Event | Chattanooga Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Public utilities requested rate increase (decrease) | $ 7,000,000 | ||||||||||||||||||||
Public utilities, requested return on equity percentage | 11.25% | ||||||||||||||||||||
Subsequent Event | energySMART [Member] | Nicor Gas | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Program duration period | 4 years | ||||||||||||||||||||
Approved infrastructure replacement program | $ 160,000,000 | ||||||||||||||||||||
Natural Gas Storage - Salt Dome Caverns | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Number of salt dome caverns | cavern | 2 | 2 | |||||||||||||||||||
Property, plant and equipment | $ 112,000,000 | $ 112,000,000 | |||||||||||||||||||
Property, Plant and Equipment | Natural Gas Storage - Salt Dome Caverns | |||||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||||||||||||
Concentration risk (as percent) | 20.00% |
Contingencies and Regulatory 87
Contingencies and Regulatory Matters - Table - Gas (Details) - Regulatory Asset Off Balance Sheet - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | $ 125 | |
Atlanta Gas Light | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | 104 | |
Virginia Natural Gas | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | 11 | |
Elizabethtown Gas | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | 8 | |
Nicor Gas | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | $ 2 | |
Predecessor | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | $ 129 | |
Predecessor | Atlanta Gas Light | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | 110 | |
Predecessor | Virginia Natural Gas | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | 11 | |
Predecessor | Elizabethtown Gas | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | 6 | |
Predecessor | Nicor Gas | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory asset | $ 2 |
Joint Ownership Agreements - Na
Joint Ownership Agreements - Narrative (Details) gal in Thousands | 6 Months Ended | 10 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Oct. 31, 2016USD ($) | Dec. 31, 2017USD ($)tranchemiMWgal | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2016 | Aug. 31, 2016 | Dec. 31, 2014miBcf | |
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Construction work in progress | $ 8,977,000,000 | $ 6,904,000,000 | $ 8,977,000,000 | ||||||
Short-term debt | 2,241,000,000 | 2,439,000,000 | 2,241,000,000 | ||||||
Earnings from equity method investments | $ 15,000,000 | 106,000,000 | 59,000,000 | $ 0 | |||||
Distributions to noncontrolling interests | $ 119,000,000 | 72,000,000 | 18,000,000 | ||||||
ALABAMA POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 14.00% | ||||||||
Construction work in progress | 491,000,000 | $ 908,000,000 | 491,000,000 | ||||||
Total megawatt capacity | MW | 1,000 | ||||||||
Jointly owned affiliate equity | $ 95,000,000 | ||||||||
Jointly owned affiliate long term debt | 125,000,000 | ||||||||
Jointly owned affiliate long term debt annual interest requirement | 4,000,000 | ||||||||
Short-term debt | 0 | $ 3,000,000 | 0 | ||||||
Ownership percentage, equity method investment | 50.00% | ||||||||
ALABAMA POWER CO | SEGCO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 86.00% | ||||||||
ALABAMA POWER CO | Southern Electric Generating Company | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Total megawatt capacity | MW | 1,020 | ||||||||
Share of purchased power | $ 76,000,000 | 55,000,000 | 76,000,000 | ||||||
Unconditional guarantee to pay outstanding pollution control revenue bond principal | 25,000,000 | ||||||||
ALABAMA POWER CO | SEGCO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Short-term debt | 14,000,000 | ||||||||
Dividends paid by equity method investment | 24,000,000 | ||||||||
GEORGIA POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Construction work in progress | 4,939,000,000 | 4,613,000,000 | 4,939,000,000 | ||||||
Short-term debt | 391,000,000 | $ 150,000,000 | 391,000,000 | ||||||
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 45.70% | ||||||||
Plant in service | $ 3,564,000,000 | ||||||||
Accumulated depreciation | $ 2,141,000,000 | ||||||||
GEORGIA POWER CO | ALABAMA POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Total megawatt capacity | MW | 1,020 | ||||||||
GEORGIA POWER CO | Intercession City Combustion Turbine | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 33.00% | ||||||||
GEORGIA POWER CO | Plant Scherer Unit 3 (coal) | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 75.00% | ||||||||
Plant in service | $ 1,232,000,000 | ||||||||
Accumulated depreciation | 468,000,000 | ||||||||
GEORGIA POWER CO | Southern Electric Generating Company | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Share of purchased power | 78,000,000 | 57,000,000 | |||||||
GULF POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Construction work in progress | 51,000,000 | 91,000,000 | 51,000,000 | ||||||
Short-term debt | 268,000,000 | $ 45,000,000 | 268,000,000 | ||||||
GULF POWER CO | Plant Daniel Units 1 & 2 (coal) | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 50.00% | ||||||||
Total megawatt capacity | MW | 1,000 | ||||||||
Plant in service | $ 696,000,000 | ||||||||
Accumulated depreciation | $ 225,000,000 | ||||||||
GULF POWER CO | Plant Scherer Unit 3 (coal) | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 25.00% | ||||||||
Total megawatt capacity | MW | 818 | ||||||||
Plant in service | $ 374,000,000 | ||||||||
Accumulated depreciation | 147,000,000 | ||||||||
SOUTHERN POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Construction work in progress | 398,000,000 | $ 511,000,000 | 398,000,000 | ||||||
Total megawatt capacity | MW | 659 | ||||||||
Short-term debt | 209,000,000 | $ 105,000,000 | 209,000,000 | ||||||
Distributions to noncontrolling interests | $ 119,000,000 | 57,000,000 | 18,000,000 | ||||||
SOUTHERN POWER CO | Plant Stanton (combined cycle) Unit A | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 65.00% | ||||||||
Plant in service | $ 155,000,000 | ||||||||
Accumulated depreciation | 55,000,000 | ||||||||
SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Construction work in progress | 496,000,000 | 491,000,000 | 496,000,000 | ||||||
Short-term debt | 1,257,000,000 | 1,518,000,000 | $ 1,257,000,000 | ||||||
Earnings from equity method investments | 60,000,000 | 106,000,000 | |||||||
Distributions to noncontrolling interests | 15,000,000 | $ 0 | |||||||
Number of tranches invested in | tranche | 7 | ||||||||
SOUTHERN Co GAS | Dalton Pipeline | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Undivided ownership interest to be leased | 50.00% | 50.00% | |||||||
Public utilities, equipment | $ 252,000,000 | ||||||||
Costs included in CWIP | 124,000,000 | $ 124,000,000 | |||||||
Pipeline infrastructure | mi | 115 | ||||||||
SOUTHERN Co GAS | Dalton Pipeline Arrangement 2 | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Undivided ownership interest to be leased | 50.00% | ||||||||
Future minimum payments receivable | $ 26,000,000 | ||||||||
Term of contract | 25 years | ||||||||
Maturity December 1, 2018 | ALABAMA POWER CO | Southern Electric Generating Company | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Guarantee of unsecured senior notes | $ 100,000,000 | ||||||||
Natural Gas Processing Plant [Member] | GEORGIA POWER CO | ALABAMA POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Total megawatt capacity | MW | 1,000 | ||||||||
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 45.70% | ||||||||
Construction work in progress | $ 3,300,000,000 | ||||||||
Predecessor | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Earnings from equity method investments | $ 2,000,000 | 6,000,000 | |||||||
Distributions to noncontrolling interests | 19,000,000 | 18,000,000 | |||||||
Purchased Power from Affiliates | GEORGIA POWER CO | Southern Electric Generating Company | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Share of purchased power | $ 78,000,000 | ||||||||
Orlando Utilities Commission | SOUTHERN POWER CO | Plant Stanton (combined cycle) Unit A | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 28.00% | ||||||||
Florida Municipal Power Agency | SOUTHERN POWER CO | Plant Stanton (combined cycle) Unit A | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 3.50% | ||||||||
Kissimmee Utility Authority | SOUTHERN POWER CO | Plant Stanton (combined cycle) Unit A | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Percent ownership | 3.50% | ||||||||
Southstar | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Ownership percentage of noncontrolling interest | 85.00% | ||||||||
Agreement to purchase remaining interest | $ 160,000,000 | ||||||||
Southstar | Piedmont | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Ownership percentage of noncontrolling interest | 15.00% | ||||||||
Georgia Natural Gas | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||
Piedmont | Southstar | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Payments of ordinary dividends to noncontrolling interests | 15,000,000 | ||||||||
Piedmont | Southstar | Predecessor | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Distributions to noncontrolling interests | 19,000,000 | $ 18,000,000 | |||||||
Southern Natural Gas Company, LLC | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Ownership percentage, equity method investment | 50.00% | ||||||||
Horizon Pipeline | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Earnings from equity method investments | 1,000,000 | $ 2,000,000 | |||||||
Pipeline infrastructure | mi | 70 | ||||||||
Horizon Pipeline | Predecessor | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Earnings from equity method investments | 1,000,000 | 2,000,000 | |||||||
PennEast Pipeline | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Ownership percentage, equity method investment | 20.00% | ||||||||
Pipeline infrastructure | mi | 118 | ||||||||
Atlantic Coast Pipeline | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Ownership percentage, equity method investment | 5.00% | ||||||||
Earnings from equity method investments | $ 1,000,000 | $ 6,000,000 | |||||||
Pipeline infrastructure | mi | 594 | ||||||||
Atlantic Coast Pipeline | Predecessor | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Earnings from equity method investments | $ 0 | $ 0 | |||||||
Pivotal JAX LNG, LLC | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Ownership percentage, equity method investment | 50.00% | ||||||||
Minimum | Horizon Pipeline | Nicor Gas | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Capacity of natural gas facility, percent | 70.00% | ||||||||
Minimum | PennEast Pipeline | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Natural gas pipeline capacity (volume) | Bcf | 1 | ||||||||
Minimum | Atlantic Coast Pipeline | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Natural gas pipeline capacity (volume) | Bcf | 1.5 | ||||||||
Maximum | Horizon Pipeline | Nicor Gas | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Capacity of natural gas facility, percent | 80.00% | ||||||||
Liquefied Natural Gas (LNG) | Pivotal JAX LNG, LLC | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Storage facility capacity | gal | 2,000 | ||||||||
Liquefied Natural Gas (LNG) | Minimum | Pivotal JAX LNG, LLC | SOUTHERN Co GAS | |||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Storage facility production capacity | gal | 120 |
Joint Ownership Agreements (Det
Joint Ownership Agreements (Details) $ in Millions | Dec. 31, 2017USD ($)MW | Aug. 31, 2016 |
ALABAMA POWER CO | ||
Jointly owned utility plant interests | ||
Percent ownership | 14.00% | |
Total megawatt capacity | MW | 1,000 | |
ALABAMA POWER CO | Plant Miller (coal) Units 1 and 2 | ||
Jointly owned utility plant interests | ||
Percent ownership | 91.84% | |
Plant in service | $ 1,717 | |
Accumulated depreciation | 619 | |
Construction Work in Progress | $ 54 | |
Total megawatt capacity | MW | 1,320 | |
ALABAMA POWER CO | Greene County | ||
Jointly owned utility plant interests | ||
Percent ownership | 60.00% | |
Plant in service | $ 172 | |
Accumulated depreciation | 65 | |
Construction Work in Progress | $ 2 | |
Total megawatt capacity | MW | 500 | |
ALABAMA POWER CO | SEGCO | ||
Jointly owned utility plant interests | ||
Percent ownership | 86.00% | |
GEORGIA POWER CO | Plant Vogtle (nuclear) Units 1 and 2 | ||
Jointly owned utility plant interests | ||
Percent ownership | 45.70% | |
Plant in service | $ 3,564 | |
Accumulated depreciation | 2,141 | |
Construction Work in Progress | $ 70 | |
GEORGIA POWER CO | Plant Hatch (nuclear) | ||
Jointly owned utility plant interests | ||
Percent ownership | 50.10% | |
Plant in service | $ 1,321 | |
Accumulated depreciation | 595 | |
Construction Work in Progress | $ 87 | |
GEORGIA POWER CO | Plant Scherer (coal) Units 1 and 2 | ||
Jointly owned utility plant interests | ||
Percent ownership | 8.40% | |
Plant in service | $ 261 | |
Accumulated depreciation | 93 | |
Construction Work in Progress | $ 8 | |
GEORGIA POWER CO | Plant Wansley (coal) | ||
Jointly owned utility plant interests | ||
Percent ownership | 53.50% | |
Plant in service | $ 1,053 | |
Accumulated depreciation | 335 | |
Construction Work in Progress | $ 72 | |
GEORGIA POWER CO | Rocky Mountain (pumped storage) | ||
Jointly owned utility plant interests | ||
Percent ownership | 25.40% | |
Plant in service | $ 182 | |
Accumulated depreciation | 132 | |
Construction Work in Progress | $ 0 | |
GEORGIA POWER CO | Plant Scherer Unit 3 (coal) | ||
Jointly owned utility plant interests | ||
Percent ownership | 75.00% | |
Plant in service | $ 1,232 | |
Accumulated depreciation | 468 | |
Construction Work in Progress | $ 26 | |
GEORGIA POWER CO | Intercession City Combustion Turbine | ||
Jointly owned utility plant interests | ||
Percent ownership | 33.00% | |
GULF POWER CO | Plant Scherer Unit 3 (coal) | ||
Jointly owned utility plant interests | ||
Percent ownership | 25.00% | |
Plant in service | $ 374 | |
Accumulated depreciation | 147 | |
Construction Work in Progress | $ 9 | |
Total megawatt capacity | MW | 818 | |
GULF POWER CO | Plant Daniel Units 1 & 2 (coal) | ||
Jointly owned utility plant interests | ||
Percent ownership | 50.00% | |
Plant in service | $ 696 | |
Accumulated depreciation | 225 | |
Construction Work in Progress | $ 4 | |
Total megawatt capacity | MW | 1,000 | |
MISSISSIPPI POWER CO | Plant Daniel Units 1 & 2 (coal) | ||
Jointly owned utility plant interests | ||
Percent ownership | 50.00% | |
SOUTHERN POWER CO | ||
Jointly owned utility plant interests | ||
Total megawatt capacity | MW | 659 | |
SOUTHERN POWER CO | Plant Stanton (combined cycle) Unit A | ||
Jointly owned utility plant interests | ||
Percent ownership | 65.00% | |
Plant in service | $ 155 | |
Accumulated depreciation | 55 | |
Construction Work in Progress | $ 0 | |
SOUTHERN POWER CO | Dalton Pipeline (natural gas pipeline) | ||
Jointly owned utility plant interests | ||
Percent ownership | 50.00% | |
Plant in service | $ 241 | |
Accumulated depreciation | 2 | |
Construction Work in Progress | $ 13 | |
GULF POWER CO | MISSISSIPPI POWER CO | Plant Daniel Units 1 & 2 (coal) | ||
Jointly owned utility plant interests | ||
Percent ownership | 50.00% | |
Plant in service | $ 713 | |
Accumulated depreciation | 189 | |
Construction Work in Progress | $ 4 | |
Total megawatt capacity | MW | 1,000 | |
ALABAMA POWER CO | MISSISSIPPI POWER CO | Greene County | ||
Jointly owned utility plant interests | ||
Percent ownership | 40.00% | |
Plant in service | $ 164 | |
Accumulated depreciation | 55 | |
Construction Work in Progress | $ 1 | |
Total megawatt capacity | MW | 500 |
Joint Ownership Agreements - Eq
Joint Ownership Agreements - Equity Method Investments - Balance Sheet Information (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | $ 1,513 | $ 1,549 |
SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | 1,477 | 1,541 |
SNG | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Current assets | 82 | 95 |
Equity investments in unconsolidated subsidiaries | 1,262 | 1,394 |
Property, plant, and equipment | 2,439 | 2,451 |
Noncurrent assets | 121 | 129 |
Total Assets | 2,642 | 2,675 |
Current liabilities | 110 | 588 |
Long-term debt | 1,102 | 706 |
Noncurrent liabilities | 76 | 22 |
Total Liabilities | 1,288 | 1,316 |
Total Stockholders' Equity | 1,354 | 1,359 |
Total Liabilities and Stockholders' Equity | 2,642 | 2,675 |
Tax Cuts and Jobs Act of 2017, change in enacted tax rate, decrease in equity method investments | 104 | |
Triton | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | 42 | 44 |
Horizon Pipeline | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | 30 | 30 |
PennEast Pipeline | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | 57 | 22 |
Atlantic Coast Pipeline | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | 41 | 33 |
Pivotal JAX LNG, LLC | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | 44 | 16 |
Other | SOUTHERN Co GAS | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investments in unconsolidated subsidiaries | $ 1 | $ 2 |
Joint Ownership Agreements - 91
Joint Ownership Agreements - Equity Method Investments - Income Statement Information (Details) - USD ($) $ in Millions | 4 Months Ended | 6 Months Ended | 10 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Oct. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | $ 15 | $ 106 | $ 59 | $ 0 | |||
SOUTHERN Co GAS | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | $ 60 | 106 | |||||
SOUTHERN Co GAS | SNG | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 56 | 88 | |||||
Revenues | $ 230 | 544 | |||||
Operating income | 138 | 246 | |||||
Net income | $ 115 | 175 | |||||
SOUTHERN Co GAS | Triton | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 2 | 4 | |||||
SOUTHERN Co GAS | Horizon Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 1 | 2 | |||||
SOUTHERN Co GAS | Atlantic Coast Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 1 | 6 | |||||
SOUTHERN Co GAS | Penn East Pipeline1 | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | $ 0 | $ 6 | |||||
SOUTHERN Co GAS | Predecessor | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | $ 2 | 6 | |||||
SOUTHERN Co GAS | Predecessor | SNG | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 0 | 0 | |||||
SOUTHERN Co GAS | Predecessor | Triton | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 1 | 4 | |||||
SOUTHERN Co GAS | Predecessor | Horizon Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 1 | 2 | |||||
SOUTHERN Co GAS | Predecessor | Atlantic Coast Pipeline | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | 0 | 0 | |||||
SOUTHERN Co GAS | Predecessor | Penn East Pipeline1 | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Earnings from equity method investments | $ 0 | $ 0 |
Joint Ownership Agreements - Re
Joint Ownership Agreements - Redeemable Noncontrolling Interest Roll Forward (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Increase (Decrease) in Temporary Equity [Roll Forward] | |||||
Beginning balance | $ 164 | ||||
Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest | (114) | ||||
Net income attributable to noncontrolling interests | 46 | $ 36 | $ 14 | ||
Distributions to noncontrolling interests | (119) | (72) | (18) | ||
Ending balance | $ 164 | 0 | 164 | ||
SOUTHERN Co GAS | |||||
Increase (Decrease) in Temporary Equity [Roll Forward] | |||||
Beginning balance | 174 | 0 | |||
Net income attributable to noncontrolling interests | 0 | 0 | |||
Distributions to noncontrolling interests | (15) | $ 0 | |||
Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable noncontrolling interest | (174) | ||||
Ending balance | 0 | $ 174 | 0 | ||
SOUTHERN Co GAS | Predecessor | |||||
Increase (Decrease) in Temporary Equity [Roll Forward] | |||||
Beginning balance | $ 41 | 0 | $ 0 | ||
Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest | 46 | ||||
Net income attributable to noncontrolling interests | 14 | 20 | |||
Distributions to noncontrolling interests | (19) | (18) | |||
Ending balance | $ 41 | $ 0 |
Income Taxes - Current and Defe
Income Taxes - Current and Deferred Income Tax Provisions (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Federal — | |||||||||||||
Current | $ (62) | $ 1,184 | $ (177) | ||||||||||
Deferred | (6) | (342) | 1,266 | ||||||||||
Total federal taxes | (68) | 842 | 1,089 | ||||||||||
State — | |||||||||||||
Current | 37 | (108) | (33) | ||||||||||
Deferred | 173 | 217 | 138 | ||||||||||
Total state taxes | 210 | 109 | 105 | ||||||||||
Income taxes | 142 | 951 | 1,194 | ||||||||||
ALABAMA POWER CO | |||||||||||||
Federal — | |||||||||||||
Current | 136 | 103 | 110 | ||||||||||
Deferred | 336 | 339 | 320 | ||||||||||
Total federal taxes | 472 | 442 | 430 | ||||||||||
State — | |||||||||||||
Current | 23 | 20 | 8 | ||||||||||
Deferred | 73 | 69 | 68 | ||||||||||
Total state taxes | 96 | 89 | 76 | ||||||||||
Income taxes | 568 | 531 | 506 | ||||||||||
GEORGIA POWER CO | |||||||||||||
Federal — | |||||||||||||
Current | 256 | 391 | 515 | ||||||||||
Deferred | 504 | 319 | 176 | ||||||||||
Total federal taxes | 760 | 710 | 691 | ||||||||||
State — | |||||||||||||
Current | 116 | 6 | 81 | ||||||||||
Deferred | (46) | 64 | (3) | ||||||||||
Total state taxes | 70 | 70 | 78 | ||||||||||
Income taxes | 830 | 780 | 769 | ||||||||||
GULF POWER CO | |||||||||||||
Federal — | |||||||||||||
Current | 19 | 34 | (3) | ||||||||||
Deferred | 58 | 45 | 80 | ||||||||||
Total federal taxes | 77 | 79 | 77 | ||||||||||
State — | |||||||||||||
Current | (1) | 0 | 5 | ||||||||||
Deferred | 14 | 12 | 10 | ||||||||||
Total state taxes | 13 | 12 | 15 | ||||||||||
Income taxes | 90 | 91 | 92 | ||||||||||
MISSISSIPPI POWER CO | |||||||||||||
Federal — | |||||||||||||
Current | 194 | (31) | (768) | ||||||||||
Deferred | (753) | (60) | 704 | ||||||||||
Total federal taxes | (559) | (91) | (64) | ||||||||||
State — | |||||||||||||
Current | 0 | (6) | (81) | ||||||||||
Deferred | 27 | (7) | 73 | ||||||||||
Total state taxes | 27 | (13) | (8) | ||||||||||
Income taxes | (532) | (104) | (72) | ||||||||||
SOUTHERN POWER CO | |||||||||||||
Federal — | |||||||||||||
Current | (566) | 928 | 12 | ||||||||||
Deferred | (312) | (1,098) | 10 | ||||||||||
Total federal taxes | (878) | (170) | 22 | ||||||||||
State — | |||||||||||||
Current | (110) | (60) | (32) | ||||||||||
Deferred | 49 | 35 | 31 | ||||||||||
Total state taxes | (61) | (25) | (1) | ||||||||||
Income taxes | $ (810) | $ (39) | $ (38) | $ (52) | $ (29) | $ (102) | $ (41) | $ (23) | (939) | $ (195) | 21 | ||
SOUTHERN Co GAS | |||||||||||||
Federal — | |||||||||||||
Current | $ 0 | 103 | |||||||||||
Deferred | 65 | 170 | |||||||||||
Total federal taxes | 65 | 273 | |||||||||||
State — | |||||||||||||
Current | (16) | 27 | |||||||||||
Deferred | 27 | 67 | |||||||||||
Total state taxes | 11 | 94 | |||||||||||
Income taxes | $ 76 | $ 367 | |||||||||||
Predecessor | SOUTHERN Co GAS | |||||||||||||
Federal — | |||||||||||||
Current | $ 67 | (13) | |||||||||||
Deferred | 8 | 198 | |||||||||||
Total federal taxes | 75 | 185 | |||||||||||
State — | |||||||||||||
Current | 12 | 10 | |||||||||||
Deferred | 0 | 18 | |||||||||||
Total state taxes | 12 | 28 | |||||||||||
Income taxes | $ 87 | $ 213 |
Income Taxes - Textual (Details
Income Taxes - Textual (Details) - USD ($) | Sep. 08, 2017 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred Credits Related to Income Taxes | $ 7,256,000,000 | $ 219,000,000 | $ 219,000,000 | $ 7,256,000,000 | $ 219,000,000 | ||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | 264,000,000 | ||||||||||||||||
Net cash payments/(refunds) for income taxes | (410,000,000) | (148,000,000) | $ (9,000,000) | ||||||||||||||
Tax regulatory assets | 825,000,000 | 825,000,000 | |||||||||||||||
Tax regulatory liabilities | 7,300,000,000 | 7,300,000,000 | |||||||||||||||
Amortization of deferred investment tax credits | 22,000,000 | 22,000,000 | 21,000,000 | ||||||||||||||
Tax credit carryforward | 9,000,000 | 9,000,000 | |||||||||||||||
Tax credit carryforward | 2,100,000,000 | 2,100,000,000 | |||||||||||||||
State investment tax credit | 318,000,000 | ||||||||||||||||
Net operating loss carryforward | 2,300,000,000 | 2,300,000,000 | |||||||||||||||
Tax positions not impacting the effective tax rate | 0 | 464,000,000 | 464,000,000 | $ 0 | 464,000,000 | 423,000,000 | |||||||||||
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | ||||||||||||||||
Unrecognized tax benefits | 18,000,000 | 484,000,000 | 484,000,000 | $ 18,000,000 | 484,000,000 | 433,000,000 | $ 170,000,000 | ||||||||||
Tax positions decrease from prior periods | 196,000,000 | 15,000,000 | 20,000,000 | ||||||||||||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 249,000,000 | 249,000,000 | |||||||||||||||
Deferred tax assets | 8,424,000,000 | 9,495,000,000 | 9,495,000,000 | 8,424,000,000 | 9,495,000,000 | ||||||||||||
Income taxes | (142,000,000) | (951,000,000) | (1,194,000,000) | ||||||||||||||
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 465,000,000 | 0 | 0 | 465,000,000 | 0 | ||||||||||||
Kemper IGCC | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Unrecognized tax benefits | $ 176,000,000 | ||||||||||||||||
Tax positions decrease from prior periods | $ 36,000,000 | ||||||||||||||||
ITC carryforward | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred tax assets | 2,420,000,000 | 1,974,000,000 | 1,974,000,000 | 2,420,000,000 | 1,974,000,000 | ||||||||||||
ALABAMA POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred Credits Related to Income Taxes | 2,082,000,000 | 65,000,000 | 65,000,000 | 2,082,000,000 | 65,000,000 | ||||||||||||
Net cash payments/(refunds) for income taxes | 236,000,000 | (108,000,000) | 121,000,000 | ||||||||||||||
Tax regulatory assets | 240,000,000 | 240,000,000 | |||||||||||||||
Tax regulatory liabilities | 2,100,000,000 | 2,100,000,000 | |||||||||||||||
Amortization of deferred investment tax credits | 7,000,000 | 8,000,000 | 8,000,000 | ||||||||||||||
Deferred tax assets | 1,028,000,000 | 1,544,000,000 | 1,544,000,000 | 1,028,000,000 | 1,544,000,000 | ||||||||||||
Income taxes | (568,000,000) | (531,000,000) | (506,000,000) | ||||||||||||||
GEORGIA POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred Credits Related to Income Taxes | 3,248,000,000 | 121,000,000 | 121,000,000 | 3,248,000,000 | 121,000,000 | ||||||||||||
Net cash payments/(refunds) for income taxes | 496,000,000 | 170,000,000 | 506,000,000 | ||||||||||||||
Amortization of deferred investment tax credits | 10,000,000 | 10,000,000 | 10,000,000 | ||||||||||||||
State investment tax credit | 50,000,000 | 42,000,000 | 33,000,000 | ||||||||||||||
Unrecognized tax benefits | 0 | 0 | |||||||||||||||
Federal tax credits | 87,000,000 | ||||||||||||||||
State investment tax credit carryforward | 318,000,000 | ||||||||||||||||
Deferred tax assets | 1,886,000,000 | 2,382,000,000 | 2,382,000,000 | 1,886,000,000 | 2,382,000,000 | ||||||||||||
Unrecognized tax benefits, income tax penalties and interest accrued | 0 | 0 | |||||||||||||||
Unrecognized tax benefits, period increase (decrease) | 0 | ||||||||||||||||
Income taxes | (830,000,000) | (780,000,000) | (769,000,000) | ||||||||||||||
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 123,000,000 | 0 | 0 | 123,000,000 | 0 | ||||||||||||
GULF POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred Credits Related to Income Taxes | 458,000,000 | 2,000,000 | 2,000,000 | 458,000,000 | 2,000,000 | ||||||||||||
Net cash payments/(refunds) for income taxes | 12,000,000 | 21,000,000 | (7,000,000) | ||||||||||||||
Tax regulatory assets | 31,000,000 | 31,000,000 | |||||||||||||||
Tax regulatory liabilities | 458,000,000 | $ 458,000,000 | |||||||||||||||
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | ||||||||||||||||
Deferred tax assets | 275,000,000 | 244,000,000 | 244,000,000 | $ 275,000,000 | 244,000,000 | ||||||||||||
Income taxes | (90,000,000) | (91,000,000) | (92,000,000) | ||||||||||||||
MISSISSIPPI POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred Credits Related to Income Taxes | 372,000,000 | 7,000,000 | 7,000,000 | 372,000,000 | 7,000,000 | ||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | 372,000,000 | ||||||||||||||||
Net cash payments/(refunds) for income taxes | (424,000,000) | (97,000,000) | (33,000,000) | ||||||||||||||
Tax regulatory assets | 36,000,000 | 36,000,000 | |||||||||||||||
Tax regulatory liabilities | 376,000,000 | 376,000,000 | |||||||||||||||
Amortization of deferred investment tax credits | 1,000,000 | 1,000,000 | 1,000,000 | ||||||||||||||
Net operating loss carryforward | 2,800,000,000 | 2,800,000,000 | |||||||||||||||
Tax positions not impacting the effective tax rate | 0 | 464,000,000 | 464,000,000 | 0 | 464,000,000 | 423,000,000 | |||||||||||
Unrecognized tax benefits | 0 | 465,000,000 | 465,000,000 | 0 | 465,000,000 | 421,000,000 | 421,000,000 | $ 165,000,000 | |||||||||
Tax positions decrease from prior periods | 177,000,000 | 0 | 0 | ||||||||||||||
Interest accrued during the period | (28,000,000) | 15,000,000 | 10,000,000 | ||||||||||||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 111,000,000 | 111,000,000 | |||||||||||||||
Deferred tax assets | 1,173,000,000 | 1,022,000,000 | 1,022,000,000 | 1,173,000,000 | 1,022,000,000 | ||||||||||||
Income taxes | 532,000,000 | 104,000,000 | 72,000,000 | ||||||||||||||
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 375,000,000 | 375,000,000 | |||||||||||||||
Deferred Tax Assets, Valuation Allowance, Income Tax Expense (Benefit) | (35,000,000) | ||||||||||||||||
SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | (743,000,000) | ||||||||||||||||
Net cash payments/(refunds) for income taxes | (487,000,000) | 116,000,000 | (518,000,000) | ||||||||||||||
Amortization of deferred investment tax credits | $ 57,000,000 | 37,000,000 | 19,000,000 | ||||||||||||||
Reduction in tax basis of assets | 50.00% | ||||||||||||||||
Net operating loss carryforward | 1,332,000,000 | $ 1,332,000,000 | |||||||||||||||
Unrecognized tax positions, penalties accrued | 0 | $ 0 | |||||||||||||||
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | ||||||||||||||||
Unrecognized tax benefits | 0 | 17,000,000 | 17,000,000 | $ 0 | 17,000,000 | 8,000,000 | $ 5,000,000 | ||||||||||
Tax positions decrease from prior periods | 17,000,000 | 8,000,000 | 6,000,000 | ||||||||||||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 61,000,000 | 61,000,000 | |||||||||||||||
Deferred tax assets | 2,693,000,000 | 2,937,000,000 | 2,937,000,000 | 2,693,000,000 | 2,937,000,000 | ||||||||||||
Income taxes | 810,000,000 | $ 39,000,000 | $ 38,000,000 | $ 52,000,000 | 29,000,000 | $ 102,000,000 | $ 41,000,000 | $ 23,000,000 | 939,000,000 | 195,000,000 | (21,000,000) | ||||||
SOUTHERN POWER CO | Unrealized Tax Credits | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred tax assets | 2,002,000,000 | 1,685,000,000 | 1,685,000,000 | 2,002,000,000 | 1,685,000,000 | ||||||||||||
SOUTHERN POWER CO | ITC carryforward | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred tax assets | 184,000,000 | 292,000,000 | 292,000,000 | 184,000,000 | 292,000,000 | ||||||||||||
SOUTHERN POWER CO | ITC carryforward | Nacogdoches Biomass Generating Plant | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Tax credit carryforward | 0 | 0 | 0 | 0 | 0 | 162,000,000 | |||||||||||
Reduction in income tax expense, investment tax credits | 18,000,000 | 173,000,000 | 54,000,000 | ||||||||||||||
SOUTHERN POWER CO | Production Tax Credit Carryforward | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Effective income tax rate reconciliation, tax credit, production, amount | 129,000,000 | 42,000,000 | 1,000,000 | ||||||||||||||
SOUTHERN Co GAS | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred Credits Related to Income Taxes | 1,063,000,000 | 22,000,000 | 22,000,000 | 1,063,000,000 | 22,000,000 | ||||||||||||
Net cash payments/(refunds) for income taxes | 23,000,000 | 72,000,000 | |||||||||||||||
Tax regulatory liabilities | 1,100,000,000 | 1,100,000,000 | |||||||||||||||
Amortization of deferred investment tax credits | 1,000,000 | 4,000,000 | |||||||||||||||
Unrecognized tax benefits | 0 | 0 | |||||||||||||||
Deferred tax assets | 849,000,000 | 598,000,000 | 598,000,000 | 849,000,000 | 598,000,000 | ||||||||||||
Unrecognized tax benefits, income tax penalties and interest accrued | 0 | 0 | |||||||||||||||
Income taxes | (76,000,000) | (367,000,000) | |||||||||||||||
Florida | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 13,000,000 | 13,000,000 | |||||||||||||||
Florida | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Net operating loss carryforward | 283,000,000 | 283,000,000 | |||||||||||||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 12,000,000 | 12,000,000 | |||||||||||||||
General Business Tax Credit Carryforward | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Tax credit carryforward | 2,000,000,000 | 2,000,000,000 | |||||||||||||||
Federal | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Net operating loss carryforward | 2,300,000,000 | 2,300,000,000 | |||||||||||||||
State | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Net operating loss carryforward | 1,300,000,000 | 1,300,000,000 | |||||||||||||||
Predecessor | SOUTHERN Co GAS | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Net cash payments/(refunds) for income taxes | $ (100,000,000) | (26,000,000) | |||||||||||||||
Amortization of deferred investment tax credits | 1,000,000 | 2,000,000 | |||||||||||||||
Unrecognized tax benefits | 0 | $ 0 | 0 | 0 | 0 | 0 | |||||||||||
Income taxes | $ (87,000,000) | (213,000,000) | |||||||||||||||
State and Local Jurisdiction | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Net operating loss carryforward | 5,607,000,000 | 5,607,000,000 | |||||||||||||||
State and Local Jurisdiction | ALABAMA POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Tax credit carryforward | 4,000,000 | 4,000,000 | |||||||||||||||
State and Local Jurisdiction | Florida | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Net operating loss carryforward | 304,000,000 | 304,000,000 | |||||||||||||||
Deferred Charges Related To Income Taxes, Current | Other Noncurrent Assets | SOUTHERN POWER CO | Unrealized Tax Credits | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Deferred tax assets | $ 316,000,000 | $ 1,130,000,000 | $ 1,130,000,000 | $ 316,000,000 | $ 1,130,000,000 | $ 246,000,000 | |||||||||||
Minimum | Scenario, Forecast | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Income taxes | $ 50,000,000 | ||||||||||||||||
Maximum | Scenario, Forecast | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Income taxes | $ 55,000,000 | ||||||||||||||||
Southern Turner Renewable Energy, LLC [Member] | SOUTHERN POWER CO | |||||||||||||||||
Income Tax Disclosure [Line Items] | |||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 10.00% |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax liabilities — | ||
Deferred income tax liabilities | $ 15,011 | $ 23,512 |
Deferred tax assets — | ||
Deferred income tax assets | 8,424 | 9,495 |
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 465 | 0 |
Valuation allowance | (149) | (23) |
Deferred tax liabilities, net | 6,736 | 14,040 |
Accumulated deferred income taxes – liability | (6,842) | (14,092) |
Portion included in accumulated deferred tax assets | (106) | (52) |
Accumulated deferred income taxes | 6,842 | 14,092 |
Accelerated depreciation | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 10,267 | 15,392 |
Property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 955 | 2,708 |
Leveraged lease basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 251 | 314 |
Employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 516 | 737 |
Deferred tax assets — | ||
Deferred income tax assets | 1,307 | 1,868 |
Premium on reacquired debt | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 54 | 89 |
Regulatory assets associated with employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 1,046 | 1,584 |
Regulatory assets associated with AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 1,225 | 1,781 |
Federal effect of state deferred taxes | ||
Deferred tax assets — | ||
Deferred income tax assets | 326 | 597 |
Over recovered fuel clause | ||
Deferred tax assets — | ||
Deferred income tax assets | 0 | 66 |
Other property basis differences | ||
Deferred tax assets — | ||
Deferred income tax assets | 446 | 401 |
Deferred costs | ||
Deferred tax assets — | ||
Deferred income tax assets | 69 | 100 |
ITC carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 2,420 | 1,974 |
Federal NOL carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 518 | 1,084 |
Unbilled revenue | ||
Deferred tax assets — | ||
Deferred income tax assets | 57 | 92 |
Other comprehensive losses | ||
Deferred tax assets — | ||
Deferred income tax assets | 84 | 152 |
AROs | ||
Deferred tax assets — | ||
Deferred income tax assets | 1,197 | 1,732 |
Estimated Loss on Kemper IGCC | ||
Deferred tax assets — | ||
Deferred income tax assets | 722 | 484 |
Deferred state tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 328 | 266 |
Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 485 | 679 |
Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 697 | 907 |
ALABAMA POWER CO | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 3,788 | 6,198 |
Deferred tax assets — | ||
Deferred income tax assets | 1,028 | 1,544 |
Deferred tax liabilities, net | 2,760 | 4,654 |
Accumulated deferred income taxes – liability | (2,760) | (4,654) |
ALABAMA POWER CO | Accelerated depreciation | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 2,336 | 4,307 |
ALABAMA POWER CO | Property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 398 | 456 |
ALABAMA POWER CO | Leveraged lease basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 16 | 26 |
ALABAMA POWER CO | Employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 162 | 201 |
Deferred tax assets — | ||
Deferred income tax assets | 286 | 427 |
ALABAMA POWER CO | Regulatory assets associated with employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 260 | 393 |
ALABAMA POWER CO | Regulatory assets associated with AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 249 | 347 |
ALABAMA POWER CO | Federal effect of state deferred taxes | ||
Deferred tax assets — | ||
Deferred income tax assets | 143 | 266 |
ALABAMA POWER CO | Unbilled revenue | ||
Deferred tax assets — | ||
Deferred income tax assets | 22 | 36 |
ALABAMA POWER CO | Other comprehensive losses | ||
Deferred tax assets — | ||
Deferred income tax assets | 10 | 19 |
ALABAMA POWER CO | Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 93 | 139 |
ALABAMA POWER CO | Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 147 | 179 |
ALABAMA POWER CO | AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 220 | 289 |
Deferred tax assets — | ||
Deferred income tax assets | 469 | 636 |
ALABAMA POWER CO | Storm damage reserves | ||
Deferred tax assets — | ||
Deferred income tax assets | 5 | 21 |
GEORGIA POWER CO | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 5,061 | 8,382 |
Deferred tax assets — | ||
Deferred income tax assets | 1,886 | 2,382 |
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 123 | 0 |
Deferred tax liabilities, net | 3,175 | 6,000 |
Accumulated deferred income taxes – liability | (3,175) | (6,000) |
GEORGIA POWER CO | Accelerated depreciation | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 3,540 | 5,266 |
GEORGIA POWER CO | Property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 0 | 957 |
GEORGIA POWER CO | Employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 287 | 428 |
Deferred tax assets — | ||
Deferred income tax assets | 423 | 661 |
GEORGIA POWER CO | Premium on reacquired debt | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 34 | 56 |
GEORGIA POWER CO | Regulatory assets associated with employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 348 | 546 |
GEORGIA POWER CO | Regulatory assets associated with AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 501 | 726 |
GEORGIA POWER CO | Federal effect of state deferred taxes | ||
Deferred tax assets — | ||
Deferred income tax assets | 72 | 173 |
GEORGIA POWER CO | Other property basis differences | ||
Deferred tax assets — | ||
Deferred income tax assets | 92 | 105 |
GEORGIA POWER CO | Deferred costs | ||
Deferred tax assets — | ||
Deferred income tax assets | 69 | 100 |
GEORGIA POWER CO | Unbilled revenue | ||
Deferred tax assets — | ||
Deferred income tax assets | 26 | 47 |
GEORGIA POWER CO | Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 30 | 70 |
GEORGIA POWER CO | Regulatory Assets Associated With Storm Damage Reserves | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 89 | 83 |
GEORGIA POWER CO | Regulatory Assets Associated With Retired Assets | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 30 | 55 |
GEORGIA POWER CO | Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 100 | 83 |
GEORGIA POWER CO | Regulatory Liabilities Associated With Asset Retirement Obligations | ||
Deferred tax assets — | ||
Deferred income tax assets | 5 | 33 |
GEORGIA POWER CO | AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 132 | 182 |
Deferred tax assets — | ||
Deferred income tax assets | 631 | 908 |
GEORGIA POWER CO | Tax credit carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 318 | 201 |
GEORGIA POWER CO | Federal Tax Credit Carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 97 | 84 |
GULF POWER CO | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 812 | 1,192 |
Deferred tax assets — | ||
Deferred income tax assets | 275 | 244 |
Deferred tax liabilities, net | 537 | 948 |
Accumulated deferred income taxes – liability | (537) | (948) |
GULF POWER CO | Accelerated depreciation | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 552 | 834 |
GULF POWER CO | Property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 105 | 123 |
GULF POWER CO | Employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 38 | 58 |
GULF POWER CO | Regulatory assets associated with employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 44 | 65 |
GULF POWER CO | Regulatory assets associated with AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 38 | 55 |
GULF POWER CO | Federal effect of state deferred taxes | ||
Deferred tax assets — | ||
Deferred income tax assets | 25 | 37 |
GULF POWER CO | Other property basis differences | ||
Deferred tax assets — | ||
Deferred income tax assets | 98 | 1 |
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 19 | 0 |
GULF POWER CO | Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 12 | 18 |
GULF POWER CO | Regulatory Assets | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 22 | 45 |
GULF POWER CO | Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 13 | 12 |
GULF POWER CO | Pension and other employee benefits | ||
Deferred tax assets — | ||
Deferred income tax assets | 49 | 72 |
GULF POWER CO | AROs | ||
Deferred tax assets — | ||
Deferred income tax assets | 38 | 55 |
GULF POWER CO | Other postretirement benefit plans | ||
Deferred tax assets — | ||
Deferred income tax assets | 17 | 26 |
GULF POWER CO | Tax credit carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 7 | 18 |
GULF POWER CO | Property damage reserves-liability | ||
Deferred tax assets — | ||
Deferred income tax assets | 10 | 17 |
MISSISSIPPI POWER CO | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 804 | 1,778 |
Deferred tax assets — | ||
Deferred income tax assets | 1,173 | 1,022 |
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | 375 | |
Valuation allowance | (122) | 0 |
Deferred tax assets, net | 247 | |
Deferred tax liabilities, net | 756 | |
Accumulated deferred income taxes – liability | 0 | (756) |
MISSISSIPPI POWER CO | Accelerated depreciation | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 373 | 386 |
MISSISSIPPI POWER CO | Property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 242 | 852 |
Deferred tax assets — | ||
Deferred income tax assets | 70 | 0 |
MISSISSIPPI POWER CO | Regulatory assets associated with employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 45 | 70 |
MISSISSIPPI POWER CO | Regulatory assets associated with AROs | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 34 | 72 |
MISSISSIPPI POWER CO | Federal effect of state deferred taxes | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 9 | 0 |
Deferred tax assets — | ||
Deferred income tax assets | 0 | 19 |
MISSISSIPPI POWER CO | Over recovered fuel clause | ||
Deferred tax assets — | ||
Deferred income tax assets | 0 | 26 |
MISSISSIPPI POWER CO | Estimated Loss on Kemper IGCC | ||
Deferred tax assets — | ||
Deferred income tax assets | 722 | 484 |
MISSISSIPPI POWER CO | Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 32 | 31 |
MISSISSIPPI POWER CO | Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 11 | 91 |
MISSISSIPPI POWER CO | NOL State Carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 133 | 113 |
MISSISSIPPI POWER CO | Ad Valorem Over Under Recovery | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 11 | 14 |
MISSISSIPPI POWER CO | Regulatory Assets For Standard Compliance | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 11 | 8 |
MISSISSIPPI POWER CO | Deferred Federal Tax Assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 0 | 31 |
MISSISSIPPI POWER CO | Pension and other employee benefits | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 28 | 49 |
Deferred tax assets — | ||
Deferred income tax assets | 62 | 96 |
MISSISSIPPI POWER CO | Federal NOL | ||
Deferred tax assets — | ||
Deferred income tax assets | 40 | 109 |
MISSISSIPPI POWER CO | Regulatory assets associated with the Kemper County energy facility | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 31 | 82 |
MISSISSIPPI POWER CO | Regulatory Assets Associated with Plant Daniel [Member] | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 9 | 13 |
MISSISSIPPI POWER CO | AROs | ||
Deferred tax assets — | ||
Deferred income tax assets | 34 | 72 |
MISSISSIPPI POWER CO | Rate differential | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 0 | 141 |
MISSISSIPPI POWER CO | Affirmative Adjustments [Member] | ||
Deferred tax assets — | ||
Deferred income tax assets | 31 | 0 |
MISSISSIPPI POWER CO | Unprotected Tax Reform Change [Member] | ||
Deferred tax assets — | ||
Deferred income tax assets | 27 | 0 |
MISSISSIPPI POWER CO | Property insurance | ||
Deferred tax assets — | ||
Deferred income tax assets | 15 | 27 |
MISSISSIPPI POWER CO | Premium on long-term debt | ||
Deferred tax assets — | ||
Deferred income tax assets | 7 | 14 |
SOUTHERN POWER CO | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 1,954 | 2,495 |
Deferred tax assets — | ||
Deferred income tax assets | 2,693 | 2,937 |
Valuation allowance | (13) | 0 |
Total, net of valuation allowances | 2,680 | 2,937 |
Deferred tax assets, net | 726 | 442 |
Accumulated deferred income taxes – liability | (199) | (152) |
SOUTHERN POWER CO | Federal effect of state deferred taxes | ||
Deferred tax assets — | ||
Deferred income tax assets | 42 | 53 |
SOUTHERN POWER CO | ITC carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 184 | 292 |
SOUTHERN POWER CO | Deferred state tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 77 | 60 |
SOUTHERN POWER CO | Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 10 | 8 |
SOUTHERN POWER CO | Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 6 | 27 |
SOUTHERN POWER CO | Accelerated depreciation and other property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 1,922 | 2,440 |
SOUTHERN POWER CO | Levelized capacity revenues | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 26 | 28 |
SOUTHERN POWER CO | Tax credit carryforward | ||
Deferred tax assets — | ||
Deferred income tax assets | 21 | 15 |
SOUTHERN POWER CO | Unrealized Tax Credits | ||
Deferred tax assets — | ||
Deferred income tax assets | 2,002 | 1,685 |
SOUTHERN POWER CO | Federal Net Operating Loss | ||
Deferred tax assets — | ||
Deferred income tax assets | 333 | 808 |
SOUTHERN POWER CO | Investment In Partnerships | ||
Deferred tax assets — | ||
Deferred income tax assets | 24 | 16 |
SOUTHERN Co GAS | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 1,927 | 2,554 |
Deferred tax assets — | ||
Deferred income tax assets | 849 | 598 |
Valuation allowance | (11) | (19) |
Total, net of valuation allowances | 838 | 579 |
Deferred tax liabilities, net | 1,089 | 1,975 |
Accumulated deferred income taxes – liability | (1,089) | (1,975) |
SOUTHERN Co GAS | Accelerated depreciation | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 1,436 | 1,954 |
SOUTHERN Co GAS | Property basis differences | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 204 | 311 |
SOUTHERN Co GAS | Employee benefit obligations | ||
Deferred tax assets — | ||
Deferred income tax assets | 185 | 165 |
SOUTHERN Co GAS | Regulatory Liability Associated With Tax Reform [Member] | ||
Deferred tax assets — | ||
Deferred income tax assets | 295 | 0 |
SOUTHERN Co GAS | Regulatory assets associated with employee benefit obligations | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 79 | 125 |
SOUTHERN Co GAS | Federal effect of state deferred taxes | ||
Deferred tax assets — | ||
Deferred income tax assets | 54 | 42 |
SOUTHERN Co GAS | Other deferred tax assets | ||
Deferred tax assets — | ||
Deferred income tax assets | 223 | 332 |
SOUTHERN Co GAS | Other deferred tax liabilities | ||
Deferred tax liabilities — | ||
Deferred income tax liabilities | 208 | 164 |
SOUTHERN Co GAS | Federal NOL | ||
Deferred tax assets — | ||
Deferred income tax assets | 92 | 59 |
Accumulated Deferred Income Taxes Assets | SOUTHERN POWER CO | ||
Deferred tax assets — | ||
Deferred tax assets, net | 925 | 594 |
Accumulated Deferred Income Taxes Liability | SOUTHERN POWER CO | ||
Deferred tax assets — | ||
Accumulated deferred income taxes – liability | $ (199) | $ (152) |
Income Taxes - NOL Carryforward
Income Taxes - NOL Carryforwards (Details) $ in Millions | Dec. 31, 2017USD ($) |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | $ 2,300 |
Approximate Net State Income Tax Benefit | 249 |
Mississippi | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 114 |
Oklahoma | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 47 |
Georgia | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 23 |
New York | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 13 |
New York City | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 15 |
Florida | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 13 |
Other states | |
Operating Loss Carryforwards [Line Items] | |
Approximate Net State Income Tax Benefit | 24 |
SOUTHERN POWER CO | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 1,332 |
Approximate Net State Income Tax Benefit | 61 |
SOUTHERN POWER CO | Oklahoma | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 978 |
Approximate Net State Income Tax Benefit | 46 |
SOUTHERN POWER CO | Florida | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 283 |
Approximate Net State Income Tax Benefit | 12 |
SOUTHERN POWER CO | South Carolina | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 48 |
Approximate Net State Income Tax Benefit | 2 |
SOUTHERN POWER CO | Other states | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 23 |
Approximate Net State Income Tax Benefit | 1 |
State and Local Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 5,607 |
State and Local Jurisdiction | Mississippi | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 2,890 |
State and Local Jurisdiction | Oklahoma | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 986 |
State and Local Jurisdiction | Georgia | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 524 |
State and Local Jurisdiction | New York | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 229 |
State and Local Jurisdiction | New York City | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 209 |
State and Local Jurisdiction | Florida | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | 304 |
State and Local Jurisdiction | Other states | |
Operating Loss Carryforwards [Line Items] | |
Approximate NOL Carryforwards | $ 465 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Federal Statutory Income Tax Rate (Details) | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
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 | 12.50% | 2.10% | 1.90% | ||
Employee stock plans dividend deduction | 4.10% | 1.20% | 1.20% | ||
Non-deductible book depreciation | 3.10% | 0.90% | 1.20% | ||
AFUDC-equity | (2.60%) | (2.00%) | (2.20%) | ||
Non-deductible equity portion on Kemper IGCC write-off | 15.70% | (0.00%) | (0.00%) | ||
ITC basis difference | (1.70%) | (5.00%) | (1.50%) | ||
Federal PTCs | (12.10%) | (1.20%) | (0.00%) | ||
Amortization of ITC | (4.20%) | (0.90%) | (0.50%) | ||
Tax Reform Legislation | (25.60%) | 0.00% | 0.00% | ||
Other | (2.70%) | (0.40%) | 0.20% | ||
Effective income tax rate | 13.30% | 27.30% | 32.90% | ||
ALABAMA POWER CO | |||||
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% | 4.20% | 3.80% | ||
Non-deductible book depreciation | 0.90% | 1.00% | 1.20% | ||
AFUDC-equity | (1.00%) | (0.70%) | (1.60%) | ||
Tax Reform Legislation | 0.30% | 0.00% | 0.00% | ||
Other | 0.00% | (0.70%) | 0.00% | ||
Effective income tax rate | 39.60% | 38.80% | 38.40% | ||
GEORGIA POWER CO | |||||
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 | 2.00% | 2.10% | 2.50% | ||
Non-deductible book depreciation | 0.70% | 0.80% | 1.20% | ||
AFUDC-equity | (0.60%) | (0.80%) | (0.70%) | ||
Tax Reform Legislation | (0.40%) | 0.00% | 0.00% | ||
Other | 0.00% | (0.40%) | (0.40%) | ||
Effective income tax rate | 36.70% | 36.70% | 37.60% | ||
GULF POWER CO | |||||
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 | 3.70% | 3.40% | 3.90% | ||
Non-deductible book depreciation | 0.20% | 0.60% | 0.50% | ||
Differences in prior years' deferred and current tax rates | 0.00% | (0.10%) | (0.10%) | ||
AFUDC-equity | (0.00%) | (0.00%) | (1.80%) | ||
Other | 0.50% | 0.60% | (0.60%) | ||
Effective income tax rate | 39.40% | 39.50% | 36.90% | ||
MISSISSIPPI POWER CO | |||||
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 | 0.60% | (5.70%) | (6.30%) | ||
Non-deductible book depreciation | 0.10% | 0.70% | 1.30% | ||
AFUDC-equity | (0.00%) | (28.50%) | (49.60%) | ||
Non-deductible equity portion on Kemper IGCC write-off | 5.30% | (0.00%) | (0.00%) | ||
Tax Reform Legislation | 11.90% | 0.00% | 0.00% | ||
Other | 0.00% | 0.00% | (2.90%) | ||
Effective income tax rate | (17.10%) | (68.50%) | (92.50%) | ||
SOUTHERN POWER CO | |||||
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 | (22.20%) | (9.10%) | (0.30%) | ||
Non-deductible equity portion on Kemper IGCC write-off | (10.00%) | (89.00%) | (21.50%) | ||
Federal PTCs | (72.50%) | (23.30%) | (0.60%) | ||
Amortization of ITC | (31.80%) | (20.60%) | (5.00%) | ||
Tax Reform Legislation | (416.10%) | 0.00% | 0.00% | ||
Other | 0.50% | 4.60% | 2.50% | ||
Noncontrolling interests | (8.60%) | (6.20%) | (1.70%) | ||
Effective income tax rate | (525.70%) | (108.60%) | 8.40% | ||
SOUTHERN Co GAS | |||||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||||
Federal statutory rate | 35.00% | 35.00% | |||
State income tax, net of federal deduction | 4.00% | 4.00% | |||
Other | 1.00% | 0.00% | |||
Effective income tax rate | 40.00% | 60.20% | |||
Predecessor | SOUTHERN Co GAS | |||||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||||
Federal statutory rate | 35.00% | 35.00% | |||
State income tax, net of federal deduction | 3.50% | 3.40% | |||
Other | (0.90%) | (2.00%) | |||
Effective income tax rate | 37.60% | 36.40% | |||
Domestic Tax Authority [Member] | SOUTHERN Co GAS | |||||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||||
Tax Reform Legislation | 15.00% | ||||
State and Local Jurisdiction | SOUTHERN Co GAS | |||||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||||
Tax Reform Legislation | 6.20% |
Income Taxes - Changes in Unrec
Income Taxes - Changes in Unrecognized Tax Benefits (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | $ 484,000,000 | $ 433,000,000 | $ 170,000,000 |
Tax positions increase from current periods | 10,000,000 | 45,000,000 | 43,000,000 |
Tax positions increase from prior periods | 10,000,000 | 21,000,000 | 240,000,000 |
Tax positions decrease from prior periods | (196,000,000) | (15,000,000) | (20,000,000) |
Reductions due to settlements | (290,000,000) | 0 | 0 |
Balance at end of year | 18,000,000 | 484,000,000 | 433,000,000 |
GEORGIA POWER CO | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Balance at end of year | 0 | ||
MISSISSIPPI POWER CO | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 465,000,000 | 421,000,000 | 421,000,000 |
Tax positions increase from current periods | 0 | 26,000,000 | 32,000,000 |
Tax positions increase from prior periods | 2,000,000 | 18,000,000 | 224,000,000 |
Tax positions decrease from prior periods | (177,000,000) | 0 | 0 |
Reductions due to settlements | (290,000,000) | 0 | 0 |
Balance at end of year | 0 | 465,000,000 | 421,000,000 |
SOUTHERN POWER CO | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 17,000,000 | 8,000,000 | 5,000,000 |
Tax positions increase from current periods | 0 | 17,000,000 | 9,000,000 |
Tax positions decrease from prior periods | (17,000,000) | (8,000,000) | (6,000,000) |
Balance at end of year | $ 0 | $ 17,000,000 | $ 8,000,000 |
Income Taxes - Impact of Unreco
Income Taxes - Impact of Unrecognized Tax Benefits on Effective Tax Rate, If Recognized (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Impact on effective tax rate | |||||
Tax positions impacting the effective tax rate | $ 18 | $ 20 | $ 10 | ||
Tax positions not impacting the effective tax rate | 0 | 464 | 423 | ||
Balance of unrecognized tax benefits | 18 | 484 | 433 | $ 170 | |
MISSISSIPPI POWER CO | |||||
Impact on effective tax rate | |||||
Tax positions impacting the effective tax rate | 0 | 1 | (2) | ||
Tax positions not impacting the effective tax rate | 0 | 464 | 423 | ||
Balance of unrecognized tax benefits | $ 0 | $ 465 | $ 421 | $ 421 | $ 165 |
Income Taxes - Accrued Interest
Income Taxes - Accrued Interest for Unrecognized Tax Benefits (Details) - MISSISSIPPI POWER CO - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward] | |||
Interest accrued at beginning of year | $ 28 | $ 13 | $ 3 |
Interest accrued during the period | (28) | 15 | 10 |
Balance at end of year | $ 0 | $ 28 | $ 13 |
Commitments - Textuals (Details
Commitments - Textuals (Details) MMBTU in Millions | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($)MMBTU | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2013 | |
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel expense | $ 4,400,000,000 | $ 4,361,000,000 | $ 4,750,000,000 | |||
Expense under purchase power agreements accounted for as operating leases | 235,000,000 | 232,000,000 | 227,000,000 | |||
Operating leases rent expense | 176,000,000 | 169,000,000 | 130,000,000 | |||
Operating leases, future minimum lease payments due | 1,527,000,000 | |||||
Leasing commitment, 2018 | 149,000,000 | |||||
Leasing commitment, 2019 | 124,000,000 | |||||
Leasing commitment, 2020 | 108,000,000 | |||||
Leasing commitment, 2021 | 95,000,000 | |||||
Leasing commitment, 2023 and thereafter | 968,000,000 | |||||
Senior notes | $ 33,000,000,000 | 35,100,000,000 | 33,000,000,000 | |||
2,022 | 83,000,000 | |||||
Barges & Railcars | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases, future minimum lease payments due | 60,000,000 | |||||
Leasing commitment, 2018 | 21,000,000 | |||||
Leasing commitment, 2019 | 11,000,000 | |||||
Leasing commitment, 2020 | 9,000,000 | |||||
Leasing commitment, 2021 | 8,000,000 | |||||
Leasing commitment, 2023 and thereafter | 5,000,000 | |||||
2,022 | 6,000,000 | |||||
ALABAMA POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel expense | 1,225,000,000 | 1,297,000,000 | 1,342,000,000 | |||
Expense under purchase power agreements accounted for as operating leases | 41,000,000 | 42,000,000 | 38,000,000 | |||
Operating leases rent expense | 25,000,000 | 18,000,000 | 19,000,000 | |||
Operating leases, future minimum lease payments due | 105,000,000 | |||||
Leasing commitment, 2018 | 21,000,000 | |||||
Leasing commitment, 2019 | 22,000,000 | |||||
Leasing commitment, 2020 | 18,000,000 | |||||
Leasing commitment, 2021 | 14,000,000 | |||||
Leasing commitment, 2023 and thereafter | 20,000,000 | |||||
Long-term pollution control bonds | 1,100,000,000 | $ 1,060,000,000 | 1,100,000,000 | |||
Percent ownership | 14.00% | |||||
2,022 | $ 10,000,000 | |||||
ALABAMA POWER CO | Barges & Railcars | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases rent expense | 11,000,000 | 14,000,000 | 13,000,000 | |||
ALABAMA POWER CO | Residual Value, Leased Property | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Leasing commitment, 2018 | 0 | |||||
Leasing commitment, 2019 | 0 | |||||
Leasing commitment, 2020 | 0 | |||||
Leasing commitment, 2021 | 0 | |||||
Leasing commitment, 2023 and thereafter | 12,000,000 | |||||
2,022 | 0 | |||||
GEORGIA POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel expense | 1,671,000,000 | 1,807,000,000 | 2,033,000,000 | |||
Operating leases rent expense | 31,000,000 | 28,000,000 | 29,000,000 | |||
Operating leases, future minimum lease payments due | $ 141,000,000 | |||||
Period of service for gas transportation supplier | 1 year | |||||
Maximum guarantee | $ 43,000,000 | |||||
Leasing commitment, 2018 | 24,000,000 | |||||
Leasing commitment, 2019 | 22,000,000 | |||||
Leasing commitment, 2020 | 20,000,000 | |||||
Leasing commitment, 2021 | 17,000,000 | |||||
Leasing commitment, 2023 and thereafter | 44,000,000 | |||||
Long-term pollution control bonds | 1,800,000,000 | 1,800,000,000 | 1,800,000,000 | |||
Senior notes | 6,200,000,000 | 7,100,000,000 | 6,200,000,000 | |||
Capacity payments | 9,000,000 | 11,000,000 | 10,000,000 | |||
Deferred capacity expense | 217,000,000 | $ 199,000,000 | 217,000,000 | 203,000,000 | ||
Percentage of minimum lease payments | 100.00% | |||||
Operating leases, contingent rent expense | $ 73,000,000 | 39,000,000 | 8,000,000 | |||
2,022 | $ 14,000,000 | |||||
GEORGIA POWER CO | Plant McIntosh | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Period of service for gas transportation supplier | 15 years | |||||
GEORGIA POWER CO | MEAG Power | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Percent ownership | 5.00% | |||||
GEORGIA POWER CO | ALABAMA POWER CO | Payment Guarantee | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Long-term pollution control bonds | $ 25,000,000 | |||||
GEORGIA POWER CO | ALABAMA POWER CO | Financial Guarantee | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Senior notes | 100,000,000 | |||||
GEORGIA POWER CO | Barges & Railcars | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases, future minimum lease payments due | 59,000,000 | |||||
Leasing commitment, 2018 | 14,000,000 | |||||
Leasing commitment, 2019 | 11,000,000 | |||||
Leasing commitment, 2020 | 9,000,000 | |||||
Leasing commitment, 2021 | 8,000,000 | |||||
Leasing commitment, 2023 and thereafter | 11,000,000 | |||||
2,022 | 6,000,000 | |||||
GEORGIA POWER CO | Residual Value, Leased Property | 2018 | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases, future minimum lease payments due | 32,000,000 | |||||
GULF POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel expense | 427,000,000 | 432,000,000 | 445,000,000 | |||
Expense under purchase power agreements accounted for as operating leases | 75,000,000 | 75,000,000 | ||||
Operating leases rent expense | 10,000,000 | 9,000,000 | 14,000,000 | |||
Operating leases, future minimum lease payments due | 20,000,000 | |||||
Leasing commitment, 2018 | 9,000,000 | |||||
Leasing commitment, 2019 | 2,000,000 | |||||
Leasing commitment, 2020 | 2,000,000 | |||||
Leasing commitment, 2021 | 1,000,000 | |||||
Leasing commitment, 2023 and thereafter | 5,000,000 | |||||
Long-term pollution control bonds | 309,000,000 | 309,000,000 | 309,000,000 | |||
Senior notes | 777,000,000 | 990,000,000 | 777,000,000 | |||
Deferred capacity expense | 119,000,000 | 97,000,000 | 119,000,000 | |||
2,022 | 1,000,000 | |||||
GULF POWER CO | Barges & Railcars | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases, future minimum lease payments due | 10,000,000 | |||||
Leasing commitment, 2018 | 2,000,000 | |||||
Leasing commitment, 2019 | 1,000,000 | |||||
Leasing commitment, 2020 | 1,000,000 | |||||
Leasing commitment, 2021 | 1,000,000 | |||||
Leasing commitment, 2023 and thereafter | 4,000,000 | |||||
2,022 | 1,000,000 | |||||
GULF POWER CO | Barges & Railcars | Plant Daniel | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel cost recovery clause | 2,000,000 | |||||
GULF POWER CO | Barge Transportation | Plant Crist and Plant Smith | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Leasing commitment, 2018 | 6,000,000 | |||||
Leasing commitment, 2019 | 5,000,000 | |||||
Fuel cost recovery clause | 7,000,000 | 5,000,000 | 10,000,000 | |||
MISSISSIPPI POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel expense | 395,000,000 | 343,000,000 | 443,000,000 | |||
Operating leases rent expense | 3,000,000 | 3,000,000 | 5,000,000 | |||
Operating leases, future minimum lease payments due | 20,000,000 | |||||
Leasing commitment, 2018 | 3,000,000 | |||||
Leasing commitment, 2019 | 3,000,000 | |||||
Leasing commitment, 2020 | 3,000,000 | |||||
Leasing commitment, 2021 | 2,000,000 | |||||
Leasing commitment, 2023 and thereafter | 7,000,000 | |||||
Long-term pollution control bonds | 83,000,000 | 83,000,000 | 83,000,000 | |||
Senior notes | 790,000,000 | $ 755,000,000 | 790,000,000 | |||
Company's share of the leases | 50.00% | |||||
Fuel cost recovery clause | $ 1,000,000 | 2,000,000 | 2,000,000 | |||
2,022 | $ 2,000,000 | |||||
MISSISSIPPI POWER CO | Plant Daniel | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Company's share of the leases | 50.00% | |||||
SOUTHERN POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Fuel expense | $ 621,000,000 | 456,000,000 | 441,000,000 | |||
Operating leases rent expense | 29,000,000 | 22,000,000 | $ 7,000,000 | |||
Leasing commitment, 2019 | 22,000,000 | |||||
Leasing commitment, 2020 | 22,000,000 | |||||
Leasing commitment, 2021 | 23,000,000 | |||||
Leasing commitment, 2023 and thereafter | 815,000,000 | |||||
Senior notes | 5,300,000,000 | 5,500,000,000 | 5,300,000,000 | |||
2,022 | 23,000,000 | |||||
SOUTHERN Co GAS | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases rent expense | 15,000,000 | |||||
Operating leases, future minimum lease payments due | 103,000,000 | |||||
Leasing commitment, 2018 | 17,000,000 | |||||
Leasing commitment, 2019 | 16,000,000 | |||||
Leasing commitment, 2020 | 16,000,000 | |||||
Leasing commitment, 2021 | 15,000,000 | |||||
Leasing commitment, 2023 and thereafter | 26,000,000 | |||||
Senior notes | 3,700,000,000 | 4,200,000,000 | $ 3,700,000,000 | |||
2,022 | 13,000,000 | |||||
Alabama Power and Georgia Power | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases, future minimum lease payments due | 44,000,000 | |||||
Tropic Equipment Leasing Inc | Financial Guarantee | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Maximum guarantee | $ 1,000,000 | |||||
Nicor Gas and Southstar | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Natural gas pipeline capacity | MMBTU | 35 | |||||
Long-term purchase commitment amount | $ 101,000,000 | |||||
Predecessor | SOUTHERN Co GAS | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Operating leases rent expense | $ 6,000,000 | $ 12,000,000 | $ 8,000,000 | |||
Minimum | ALABAMA POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 5 years | |||||
Minimum | GEORGIA POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 5 years | |||||
Minimum | GULF POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 5 years | |||||
Maximum | ALABAMA POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 10 years | |||||
Lessee, Operating Lease, Renewal Term | 20 years | |||||
Maximum | GEORGIA POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 10 years | |||||
Lessee, Operating Lease, Renewal Term | 20 years | |||||
Maximum | GULF POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 10 years | |||||
Lessee, Operating Lease, Renewal Term | 5 years | |||||
Maximum | MISSISSIPPI POWER CO | ||||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||||
Lessee, Operating Lease, Term of Contract | 10 years | |||||
Lessee, Operating Lease, Renewal Term | 20 years |
Commitments - Estimated Long-te
Commitments - Estimated Long-term obligations (Details) $ in Millions | Dec. 31, 2017USD ($) |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | $ 149 |
2,019 | 124 |
2,020 | 108 |
2,021 | 95 |
2,022 | 83 |
2023 and thereafter | 968 |
Total | 1,527 |
ALABAMA POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 21 |
2,019 | 22 |
2,020 | 18 |
2,021 | 14 |
2,022 | 10 |
2023 and thereafter | 20 |
Total | 105 |
Future minimum sublease rentals | 3 |
SOUTHERN POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,019 | 22 |
2,020 | 22 |
2,021 | 23 |
2,022 | 23 |
2023 and thereafter | 815 |
GEORGIA POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 219 |
2,019 | 220 |
2,020 | 216 |
2,021 | 220 |
2,022 | 221 |
2023 and thereafter | 1,405 |
Total | 2,501 |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 24 |
2,019 | 22 |
2,020 | 20 |
2,021 | 17 |
2,022 | 14 |
2023 and thereafter | 44 |
Total | 141 |
GULF POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 9 |
2,019 | 2 |
2,020 | 2 |
2,021 | 1 |
2,022 | 1 |
2023 and thereafter | 5 |
Total | 20 |
MISSISSIPPI POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 3 |
2,019 | 3 |
2,020 | 3 |
2,021 | 2 |
2,022 | 2 |
2023 and thereafter | 7 |
Total | 20 |
SOUTHERN Co GAS | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 17 |
2,019 | 16 |
2,020 | 16 |
2,021 | 15 |
2,022 | 13 |
2023 and thereafter | 26 |
Total | 103 |
Affiliate Operating Lease PPA | MISSISSIPPI POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 2 |
2,019 | 2 |
2,020 | 2 |
2,021 | 2 |
2,022 | 2 |
2023 and thereafter | 7 |
Total | 17 |
Affiliate Operating Lease | ALABAMA POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 8 |
2,019 | 10 |
2,020 | 8 |
2,021 | 7 |
2,022 | 5 |
2023 and thereafter | 16 |
Total | 54 |
Barges & Railcars | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 21 |
2,019 | 11 |
2,020 | 9 |
2,021 | 8 |
2,022 | 6 |
2023 and thereafter | 5 |
Total | 60 |
Barges & Railcars | GEORGIA POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 14 |
2,019 | 11 |
2,020 | 9 |
2,021 | 8 |
2,022 | 6 |
2023 and thereafter | 11 |
Total | 59 |
Barges & Railcars | GULF POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 2 |
2,019 | 1 |
2,020 | 1 |
2,021 | 1 |
2,022 | 1 |
2023 and thereafter | 4 |
Total | 10 |
Other | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 128 |
2,019 | 113 |
2,020 | 99 |
2,021 | 87 |
2,022 | 77 |
2023 and thereafter | 963 |
Total | 1,467 |
Other | GULF POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 7 |
2,019 | 1 |
2,020 | 1 |
2,021 | 0 |
2,022 | 0 |
2023 and thereafter | 1 |
Total | 10 |
Railcars | ALABAMA POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 7 |
2,019 | 7 |
2,020 | 7 |
2,021 | 6 |
2,022 | 5 |
2023 and thereafter | 4 |
Total | 36 |
Vehicles & Other | ALABAMA POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 6 |
2,019 | 5 |
2,020 | 3 |
2,021 | 1 |
2,022 | 0 |
2023 and thereafter | 0 |
Total | 15 |
Non-Affiliate Operating Lease | MISSISSIPPI POWER CO | |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 1 |
2,019 | 1 |
2,020 | 1 |
2,021 | 0 |
2,022 | 0 |
2023 and thereafter | 0 |
Total | 3 |
Operating Lease PPA | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 247 |
2,019 | 250 |
2,020 | 247 |
2,021 | 249 |
2,022 | 252 |
2023 and thereafter | 806 |
Total | 2,051 |
Non-Affiliate Operating Lease PPA | GEORGIA POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 127 |
2,019 | 128 |
2,020 | 124 |
2,021 | 125 |
2,022 | 126 |
2023 and thereafter | 773 |
Total | 1,403 |
Plant Vogtle (nuclear) Units 1 and 2 | GEORGIA POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 7 |
2,019 | 6 |
2,020 | 4 |
2,021 | 5 |
2,022 | 4 |
2023 and thereafter | 38 |
Total | 64 |
Affiliate Capital Lease PPA | GEORGIA POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 23 |
2,019 | 23 |
2,020 | 23 |
2,021 | 24 |
2,022 | 24 |
2023 and thereafter | 182 |
Total | 299 |
Minimum Lease Payments, Capital Leases [Abstract] | |
Less: amounts representing executory costs | 45 |
Net minimum lease payments | 254 |
Less: amounts representing interest | 120 |
Present value of net minimum lease payments | 134 |
Affiliate Operating Lease PPA | GEORGIA POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 62 |
2,019 | 63 |
2,020 | 65 |
2,021 | 66 |
2,022 | 67 |
2023 and thereafter | 412 |
Total | 735 |
Minimum Lease Payments, Operating Leases [Abstract] | |
2,018 | 10 |
2,019 | 11 |
2,020 | 11 |
2,021 | 9 |
2,022 | 8 |
2023 and thereafter | 33 |
Total | 82 |
Purchased Power | ALABAMA POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 41 |
2,019 | 43 |
2,020 | 44 |
2,021 | 46 |
2,022 | 47 |
2023 and thereafter | 0 |
Total | 221 |
Purchased Power | GULF POWER CO | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 79 |
2,019 | 79 |
2,020 | 79 |
2,021 | 79 |
2,022 | 79 |
2023 and thereafter | 33 |
Total | 428 |
Other | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |
2,018 | 7 |
2,019 | 6 |
2,020 | 4 |
2,021 | 5 |
2,022 | 4 |
2023 and thereafter | 38 |
Total | $ 64 |
Commitments - Contractual Oblig
Commitments - Contractual Obligations - Pipeline Charges, Storage Capacity, and Gas Supply (Details) - Pipeline Charges, Storage Capacity, and Gas Supply $ in Millions | Dec. 31, 2017USD ($) |
Long-term Purchase Commitment [Line Items] | |
2,018 | $ 813 |
2,019 | 552 |
2,020 | 416 |
2,021 | 375 |
2,022 | 339 |
2023 and thereafter | 2,294 |
Total | 4,789 |
SOUTHERN Co GAS | |
Long-term Purchase Commitment [Line Items] | |
Total | $ 4,789 |
Financing - Textual (Details)
Financing - Textual (Details) | Oct. 26, 2016 | Feb. 20, 2014USD ($) | Dec. 31, 2017USD ($)leased_asset_unitsseries$ / sharesshares | Nov. 30, 2017USD ($)shares | Oct. 31, 2017USD ($)shares | Sep. 30, 2017USD ($)$ / sharesshares | Aug. 31, 2017USD ($) | Jul. 31, 2017USD ($) | Jun. 30, 2017USD ($)agreementshares | May 31, 2017USD ($) | Feb. 28, 2017USD ($) | Jan. 31, 2017USD ($)shares | Sep. 30, 2013 | Feb. 20, 2018USD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2017USD ($)leased_asset_unitsseries$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($) | Dec. 31, 2012USD ($) | Jan. 04, 2018USD ($) | Nov. 01, 2017USD ($) | Oct. 04, 2017USD ($) | Sep. 29, 2017USD ($) | Aug. 10, 2017USD ($) | Apr. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 08, 2016USD ($) | Aug. 31, 2015 | Dec. 31, 2014USD ($) | Dec. 31, 2013 |
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Line of Credit Terminated | $ 1,000,000,000 | ||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | $ 3,892,000,000 | $ 2,587,000,000 | $ 3,892,000,000 | $ 2,587,000,000 | |||||||||||||||||||||||||||||
2,022 | 2,016,000,000 | 1,378,000,000 | 2,016,000,000 | 1,378,000,000 | |||||||||||||||||||||||||||||
Redeemable preferred stock | 324,000,000 | 118,000,000 | 324,000,000 | 118,000,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Proceeds from issuance of junior subordinated notes | 206,000,000 | 206,000,000 | 206,000,000 | 206,000,000 | |||||||||||||||||||||||||||||
Other long-term debt | 10,987,000,000 | 9,404,000,000 | 10,987,000,000 | 9,404,000,000 | |||||||||||||||||||||||||||||
Senior notes, current | 2,354,000,000 | 1,995,000,000 | 2,354,000,000 | 1,995,000,000 | |||||||||||||||||||||||||||||
Other Long-term Debt | 1,420,000,000 | 485,000,000 | 1,420,000,000 | 485,000,000 | |||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 3,900,000,000 | 3,900,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2019 | 3,200,000,000 | 3,200,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2020 | 3,200,000,000 | 3,200,000,000 | |||||||||||||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in 2021 | 3,100,000,000 | 3,100,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2022 | 2,200,000,000 | 2,200,000,000 | |||||||||||||||||||||||||||||||
2,018 | 2,402,000,000 | 2,403,000,000 | 2,402,000,000 | 2,403,000,000 | |||||||||||||||||||||||||||||
2,019 | 3,074,000,000 | 3,076,000,000 | 3,074,000,000 | 3,076,000,000 | |||||||||||||||||||||||||||||
Long-term debt, maturities, repayments of principal after year five | $ 22,142,000,000 | 20,369,000,000 | $ 22,142,000,000 | 20,369,000,000 | |||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 70.00% | 70.00% | 65.00% | ||||||||||||||||||||||||||||||
Senior notes | $ 35,100,000,000 | 33,000,000,000 | $ 35,100,000,000 | 33,000,000,000 | |||||||||||||||||||||||||||||
Capitalized lease obligations | 204,000,000 | 136,000,000 | 204,000,000 | 136,000,000 | |||||||||||||||||||||||||||||
Accumulated depreciation PPE | 31,457,000,000 | 29,852,000,000 | 31,457,000,000 | 29,852,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 8,094,000,000 | 8,094,000,000 | |||||||||||||||||||||||||||||||
Amount of variable rate pollution control revenue bonds outstanding requiring liquidity support | 1,500,000,000 | 1,900,000,000 | 1,500,000,000 | 1,900,000,000 | |||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | $ 2,439,000,000 | $ 2,032,000,000 | 2,439,000,000 | $ 2,032,000,000 | |||||||||||||||||||||||||||||
Remarketed pollution control bonds | $ 714,000,000 | ||||||||||||||||||||||||||||||||
Common stock, shares issued | shares | 1,000,000,000 | 991,000,000 | 1,000,000,000 | 991,000,000 | |||||||||||||||||||||||||||||
Common stock | $ 793,000,000 | $ 3,758,000,000 | $ 256,000,000 | ||||||||||||||||||||||||||||||
Short-term debt | $ 2,439,000,000 | $ 2,241,000,000 | $ 2,439,000,000 | 2,241,000,000 | |||||||||||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | ||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 8,145,000,000 | $ 8,145,000,000 | |||||||||||||||||||||||||||||||
2,020 | 2,273,000,000 | 1,326,000,000 | 2,273,000,000 | 1,326,000,000 | |||||||||||||||||||||||||||||
Capitalized leases | 31,000,000 | 32,000,000 | 31,000,000 | 32,000,000 | |||||||||||||||||||||||||||||
Unamortized debt issuance expense | (3,000,000) | (1,000,000) | (3,000,000) | (1,000,000) | |||||||||||||||||||||||||||||
2,021 | 2,643,000,000 | 2,655,000,000 | 2,643,000,000 | 2,655,000,000 | |||||||||||||||||||||||||||||
Expires, 2018 | 195,000,000 | 195,000,000 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 725,000,000 | 725,000,000 | |||||||||||||||||||||||||||||||
Assets | 111,005,000,000 | 109,697,000,000 | 111,005,000,000 | 109,697,000,000 | 78,318,000,000 | ||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Value | 609,000,000 | 150,000,000 | |||||||||||||||||||||||||||||||
Subsequent Event | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Remarketed pollution control bonds | $ 50,000,000 | ||||||||||||||||||||||||||||||||
Building | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Capital leased assets, gross | 216,000,000 | 61,000,000 | 216,000,000 | 61,000,000 | |||||||||||||||||||||||||||||
Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Junior subordinated notes | 3,570,000,000 | 2,350,000,000 | 3,570,000,000 | 2,350,000,000 | |||||||||||||||||||||||||||||
Trust Preferred Securities Subject to Mandatory Redemption | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred securities, outstanding | 200,000,000 | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||||||
Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 300,000,000 | 300,000,000 | |||||||||||||||||||||||||||||||
Floating rate Promissory Note Due July 2018 | Subsequent Event | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 100,000,000 | ||||||||||||||||||||||||||||||||
Subsidiaries | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Capitalized lease obligations | $ 177,000,000 | 29,000,000 | $ 177,000,000 | 29,000,000 | |||||||||||||||||||||||||||||
Subsidiaries | Capital Lease Obligations | Minimum | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.50% | 1.50% | |||||||||||||||||||||||||||||||
Subsidiaries | Capital Lease Obligations | Maximum | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.70% | 4.70% | |||||||||||||||||||||||||||||||
Parent Company | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Bank loans | $ 450,000,000 | 400,000,000 | $ 450,000,000 | 400,000,000 | |||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 70.00% | 70.00% | |||||||||||||||||||||||||||||||
Senior notes | $ 10,200,000,000 | 10,300,000,000 | $ 10,200,000,000 | 10,300,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 1,999,000,000 | 1,999,000,000 | |||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 2,000,000,000 | 2,000,000,000 | |||||||||||||||||||||||||||||||
Expires, 2018 | 0 | 0 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 0 | 0 | |||||||||||||||||||||||||||||||
Parent Company | Notes Payable to Banks [Member] | Floating Rate Bank Term Loan Agreement [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Number of Loan Agreements | agreement | 2 | ||||||||||||||||||||||||||||||||
Parent Company | Notes Payable to Banks [Member] | Floating Rate Bank Term Loan Agreement 4 [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 100,000,000 | $ 100,000,000 | |||||||||||||||||||||||||||||||
Parent Company | Junior Subordinated Debt | Senior Notes Due 2076 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 500,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.325% | ||||||||||||||||||||||||||||||||
Parent Company | Junior Subordinated Debt | Junior Subordinated Notes Due Two Thousand Seventy Seven [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 450,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.25% | ||||||||||||||||||||||||||||||||
Parent Company | Line of Credit | Uncommitted Bank Credit Arrangement [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Proceeds from Issuance of Debt | $ 250,000,000 | ||||||||||||||||||||||||||||||||
Debt Instrument, Payable by Demand from Bank, Term | 30 days | ||||||||||||||||||||||||||||||||
ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 0 | 561,000,000 | 0 | 561,000,000 | |||||||||||||||||||||||||||||
2,022 | $ 750,000,000 | 200,000,000 | $ 750,000,000 | 200,000,000 | |||||||||||||||||||||||||||||
Ownership percentage, equity method investment | 50.00% | 50.00% | |||||||||||||||||||||||||||||||
Redeemable preferred stock | $ 291,000,000 | 85,000,000 | $ 291,000,000 | 85,000,000 | |||||||||||||||||||||||||||||
Senior notes and pollution control revenue bonds, current | 0 | 561,000,000 | 0 | 561,000,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Proceeds from issuance of junior subordinated notes | 206,000,000 | 206,000,000 | 206,000,000 | 206,000,000 | |||||||||||||||||||||||||||||
Other long-term debt | 1,060,000,000 | 1,096,000,000 | 1,060,000,000 | 1,096,000,000 | |||||||||||||||||||||||||||||
2,019 | 200,000,000 | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||||||
Long-term debt, maturities, repayments of principal after year five | 4,975,000,000 | 4,425,000,000 | 4,975,000,000 | 4,425,000,000 | |||||||||||||||||||||||||||||
Bank loans | $ 45,000,000 | 45,000,000 | $ 45,000,000 | 45,000,000 | |||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | |||||||||||||||||||||||||||||||
Percent ownership | 14.00% | 14.00% | |||||||||||||||||||||||||||||||
Pollution control revenue bonds, outstanding | $ 1,060,000,000 | 1,100,000,000 | $ 1,060,000,000 | 1,100,000,000 | |||||||||||||||||||||||||||||
Repayments of senior debt | 525,000,000 | 200,000,000 | 650,000,000 | ||||||||||||||||||||||||||||||
Capitalized lease obligations | 4,000,000 | 4,000,000 | 4,000,000 | 4,000,000 | |||||||||||||||||||||||||||||
Accumulated depreciation PPE | 9,563,000,000 | 9,112,000,000 | 9,563,000,000 | 9,112,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 1,335,000,000 | 1,335,000,000 | |||||||||||||||||||||||||||||||
Amount of variable rate pollution control revenue bonds outstanding requiring liquidity support | 854,000,000 | 854,000,000 | |||||||||||||||||||||||||||||||
Pollution control revenue bonds required to be remarketed | 120,000,000 | 120,000,000 | |||||||||||||||||||||||||||||||
Short-term debt outstanding, regulatory approved maximum | 2,000,000,000 | 2,000,000,000 | |||||||||||||||||||||||||||||||
Short-term debt | 3,000,000 | 0 | $ 3,000,000 | 0 | |||||||||||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.10% | ||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,335,000,000 | $ 1,335,000,000 | |||||||||||||||||||||||||||||||
2,020 | 250,000,000 | 250,000,000 | 250,000,000 | 250,000,000 | |||||||||||||||||||||||||||||
2,021 | 220,000,000 | 220,000,000 | 220,000,000 | 220,000,000 | |||||||||||||||||||||||||||||
Capital contributions from parent company | 361,000,000 | 260,000,000 | 22,000,000 | ||||||||||||||||||||||||||||||
Expires, 2018 | 35,000,000 | 35,000,000 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 500,000,000 | $ 500,000,000 | 500,000,000 | ||||||||||||||||||||||||||||||
Assets | 23,864,000,000 | 22,516,000,000 | 23,864,000,000 | 22,516,000,000 | |||||||||||||||||||||||||||||
ALABAMA POWER CO | Trust Preferred Securities Subject to Mandatory Redemption | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred securities, outstanding | 200,000,000 | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||||||
ALABAMA POWER CO | Senior Notes And Pollution Control Bond | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
2,022 | 750,000,000 | 750,000,000 | |||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
2,018 | 0 | 0 | |||||||||||||||||||||||||||||||
2,019 | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||||||||
2,020 | 250,000,000 | 250,000,000 | |||||||||||||||||||||||||||||||
2,021 | 310,000,000 | 310,000,000 | |||||||||||||||||||||||||||||||
ALABAMA POWER CO | Bank Loans [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 45,000,000 | $ 45,000,000 | 45,000,000 | $ 45,000,000 | |||||||||||||||||||||||||||||
ALABAMA POWER CO | Capital Lease Obligations | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 6.90% | 6.90% | |||||||||||||||||||||||||||||||
ALABAMA POWER CO | Senior Notes | Series 2016A | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 550,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 2.45% | ||||||||||||||||||||||||||||||||
ALABAMA POWER CO | Senior Notes | Series 2017B | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 550,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.70% | ||||||||||||||||||||||||||||||||
ALABAMA POWER CO | Unsecured Debt | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Senior notes | 6,400,000,000 | $ 5,800,000,000 | 6,400,000,000 | $ 5,800,000,000 | |||||||||||||||||||||||||||||
ALABAMA POWER CO | Line of Credit | Alabama Power Company Project | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | $ 36,100,000 | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 857,000,000 | 460,000,000 | 857,000,000 | 460,000,000 | |||||||||||||||||||||||||||||
2,022 | 400,000,000 | 400,000,000 | 400,000,000 | 400,000,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Other long-term debt | 4,716,000,000 | 4,445,000,000 | 4,716,000,000 | 4,445,000,000 | |||||||||||||||||||||||||||||
Senior notes, current | 750,000,000 | 450,000,000 | 750,000,000 | 450,000,000 | |||||||||||||||||||||||||||||
Other Long-term Debt | 100,000,000 | 0 | 100,000,000 | 0 | |||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2017 | 861,000,000 | 861,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2019 | 513,000,000 | 513,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2020 | 1,000,000,000 | 1,000,000,000 | |||||||||||||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in 2021 | 375,000,000 | 375,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2022 | 518,000,000 | 518,000,000 | |||||||||||||||||||||||||||||||
2,018 | 747,000,000 | 748,000,000 | 747,000,000 | 748,000,000 | |||||||||||||||||||||||||||||
2,019 | 499,000,000 | 500,000,000 | 499,000,000 | 500,000,000 | |||||||||||||||||||||||||||||
Long-term debt, maturities, repayments of principal after year five | 4,175,000,000 | 3,775,000,000 | 4,175,000,000 | 3,775,000,000 | |||||||||||||||||||||||||||||
Bank loans | $ 250,000,000 | $ 250,000,000 | |||||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 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 | 0.375% | ||||||||||||||||||||||||||||||||
Senior notes | $ 7,100,000,000 | 6,200,000,000 | $ 7,100,000,000 | 6,200,000,000 | |||||||||||||||||||||||||||||
Amortization period for line of credit facility | 5 years | ||||||||||||||||||||||||||||||||
Pollution control revenue bonds, outstanding | $ 1,800,000,000 | 1,800,000,000 | $ 1,800,000,000 | 1,800,000,000 | |||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 2.00% | 2.00% | |||||||||||||||||||||||||||||||
Repayments of senior debt | $ 450,000,000 | 700,000,000 | 1,175,000,000 | ||||||||||||||||||||||||||||||
Capitalized lease obligations | $ 154,000,000 | 169,000,000 | 154,000,000 | 169,000,000 | |||||||||||||||||||||||||||||
Accumulated depreciation PPE | 11,704,000,000 | 11,317,000,000 | 11,704,000,000 | 11,317,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 1,732,000,000 | 1,732,000,000 | |||||||||||||||||||||||||||||||
Amount of variable rate pollution control revenue bonds outstanding requiring liquidity support | 550,000,000 | 868,000,000 | 550,000,000 | 868,000,000 | |||||||||||||||||||||||||||||
Pollution control revenue bonds required to be remarketed | 469,000,000 | 469,000,000 | |||||||||||||||||||||||||||||||
Short-term debt | 150,000,000 | 391,000,000 | $ 150,000,000 | 391,000,000 | |||||||||||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | ||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,750,000,000 | $ 1,750,000,000 | |||||||||||||||||||||||||||||||
2,020 | 950,000,000 | 0 | 950,000,000 | 0 | |||||||||||||||||||||||||||||
Capitalized leases | 11,000,000 | 10,000,000 | 11,000,000 | 10,000,000 | |||||||||||||||||||||||||||||
Unamortized debt issuance expense | (1,000,000) | 0 | (1,000,000) | 0 | |||||||||||||||||||||||||||||
2,021 | 325,000,000 | 325,000,000 | 325,000,000 | 325,000,000 | |||||||||||||||||||||||||||||
Capital contributions from parent company | 431,000,000 | 594,000,000 | 62,000,000 | ||||||||||||||||||||||||||||||
Expires, 2018 | 0 | 0 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 0 | 0 | |||||||||||||||||||||||||||||||
Assets | $ 36,779,000,000 | 34,835,000,000 | $ 36,779,000,000 | 34,835,000,000 | |||||||||||||||||||||||||||||
Preference stock, shares outstanding | shares | 0 | 0 | |||||||||||||||||||||||||||||||
GEORGIA POWER CO | Corporate, Non-Segment | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Capital leased assets, gross | $ 61,000,000 | $ 61,000,000 | |||||||||||||||||||||||||||||||
Capitalized lease obligations | 61,000,000 | 61,000,000 | |||||||||||||||||||||||||||||||
Accumulated depreciation PPE | 39,000,000 | 33,000,000 | 39,000,000 | 33,000,000 | |||||||||||||||||||||||||||||
GEORGIA POWER CO | Building | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Capitalized lease obligations | 22,000,000 | 28,000,000 | 22,000,000 | 28,000,000 | |||||||||||||||||||||||||||||
GEORGIA POWER CO | Municipal Bonds [Member] | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995 [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 27,000,000 | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Municipal Bonds [Member] | Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997 [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 38,000,000 | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Notes Payable to Banks [Member] | Floating Rate Bank Term Loan Agreement [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Number of Loan Agreements | agreement | 3 | ||||||||||||||||||||||||||||||||
Debt Instrument, Payable by Demand from Bank, Term | 30 days | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Notes Payable to Banks [Member] | Bank Term Loans | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Long-term debt | $ 250,000,000 | $ 0 | $ 250,000,000 | $ 0 | |||||||||||||||||||||||||||||
GEORGIA POWER CO | Notes Payable to Banks [Member] | Floating Rate Bank Term Loan Agreement 1 [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 50,000,000 | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Notes Payable to Banks [Member] | Floating Rate Bank Term Loan Agreement 2 [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 150,000,000 | 150,000,000 | |||||||||||||||||||||||||||||||
GEORGIA POWER CO | Notes Payable to Banks [Member] | Floating Rate Bank Term Loan Agreement 3 [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 100,000,000 | 100,000,000 | |||||||||||||||||||||||||||||||
GEORGIA POWER CO | Capital Lease Obligations | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.90% | 7.90% | 7.90% | 7.90% | |||||||||||||||||||||||||||||
GEORGIA POWER CO | Secured Debt | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Long-term debt | $ 2,800,000,000 | $ 2,800,000,000 | |||||||||||||||||||||||||||||||
GEORGIA POWER CO | Secured Debt | FFB Loan | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Long-term debt | 2,600,000,000 | $ 2,600,000,000 | 2,600,000,000 | $ 2,600,000,000 | |||||||||||||||||||||||||||||
GEORGIA POWER CO | Senior Notes | Series 2007A Preference Stock [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Shares | shares | 2,250,000 | ||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Value | $ 225,000,000 | ||||||||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.50% | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Senior Notes | Series 2016B | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 400,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.25% | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Senior Notes | Series 2016A | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 450,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 2.00% | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Senior Notes | Series 2017C | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 500,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 2.00% | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Senior Notes | Preferred Class A [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Shares | shares | 1,800,000 | ||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Value | $ 45,000,000 | ||||||||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.125% | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Junior Subordinated Debt | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Long-term debt | 270,000,000 | 0 | 270,000,000 | 0 | |||||||||||||||||||||||||||||
GEORGIA POWER CO | Junior Subordinated Debt | Series 2017A [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.00% | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Line of Credit | Uncommitted Bank Credit Arrangement [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | 250,000,000 | $ 250,000,000 | |||||||||||||||||||||||||||||||
Proceeds from Issuance of Debt | 500,000,000 | ||||||||||||||||||||||||||||||||
GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Percent ownership | 45.70% | ||||||||||||||||||||||||||||||||
GULF POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 0 | 87,000,000 | 0 | 87,000,000 | |||||||||||||||||||||||||||||
2,022 | 141,000,000 | 141,000,000 | |||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Other long-term debt | 309,000,000 | 309,000,000 | 309,000,000 | 309,000,000 | |||||||||||||||||||||||||||||
2,018 | 0 | 0 | |||||||||||||||||||||||||||||||
2,019 | $ 0 | $ 0 | |||||||||||||||||||||||||||||||
Bank loans | 100,000,000 | 100,000,000 | |||||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | |||||||||||||||||||||||||||||||
Line of credit facility, amount available to support variable rate pollution control revenue bonds | $ 82,000,000 | $ 82,000,000 | |||||||||||||||||||||||||||||||
Senior notes | 990,000,000 | 777,000,000 | 990,000,000 | 777,000,000 | |||||||||||||||||||||||||||||
Secured debt | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | |||||||||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 309,000,000 | 309,000,000 | 309,000,000 | 309,000,000 | |||||||||||||||||||||||||||||
Repayments of senior debt | 85,000,000 | 235,000,000 | 60,000,000 | ||||||||||||||||||||||||||||||
Accumulated depreciation PPE | 1,461,000,000 | 1,382,000,000 | 1,461,000,000 | 1,382,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 280,000,000 | 280,000,000 | |||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 268,000,000 | 268,000,000 | |||||||||||||||||||||||||||||||
Pollution control revenue bonds required to be remarketed | $ 75,000,000 | 75,000,000 | |||||||||||||||||||||||||||||||
Common stock, shares issued | shares | 1,750,000 | ||||||||||||||||||||||||||||||||
Common stock | $ 175,000,000 | $ 175,000,000 | 0 | 20,000,000 | |||||||||||||||||||||||||||||
Number of issuance pollution control revenue bonds | series | 2 | 2 | |||||||||||||||||||||||||||||||
Short-term debt | $ 45,000,000 | 268,000,000 | $ 45,000,000 | 268,000,000 | |||||||||||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | ||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 280,000,000 | $ 195,000,000 | $ 280,000,000 | ||||||||||||||||||||||||||||||
2,020 | 175,000,000 | 175,000,000 | 175,000,000 | 175,000,000 | |||||||||||||||||||||||||||||
2,021 | 0 | 0 | |||||||||||||||||||||||||||||||
Capital contributions from parent company | 2,000,000 | 20,000,000 | 4,000,000 | ||||||||||||||||||||||||||||||
Expires, 2018 | 30,000,000 | 30,000,000 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 225,000,000 | 225,000,000 | |||||||||||||||||||||||||||||||
Assets | 4,797,000,000 | 4,822,000,000 | 4,797,000,000 | 4,822,000,000 | |||||||||||||||||||||||||||||
GULF POWER CO | Secured Debt | Plant Daniel | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 41,000,000 | 41,000,000 | |||||||||||||||||||||||||||||||
GULF POWER CO | Series 2011A | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Redemption amount of principal notes | $ 300,000,000 | ||||||||||||||||||||||||||||||||
GULF POWER CO | Long-term Debt, Current | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
2,018 | 87,000,000 | 87,000,000 | |||||||||||||||||||||||||||||||
GULF POWER CO | Bank Loans [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 100,000,000 | 100,000,000 | |||||||||||||||||||||||||||||||
GULF POWER CO | Senior Notes | Series 2007A Preference Stock [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Shares | shares | 450,000 | ||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Value | $ 45,000,000 | ||||||||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.45% | ||||||||||||||||||||||||||||||||
GULF POWER CO | Senior Notes | Series 2011A | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.30% | ||||||||||||||||||||||||||||||||
GULF POWER CO | Senior Notes | Series 2007A [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | $ 85,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.90% | ||||||||||||||||||||||||||||||||
GULF POWER CO | Senior Notes | Series Preference Stock [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Shares | shares | 550,000 | ||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Value | $ 55,000,000 | ||||||||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.00% | ||||||||||||||||||||||||||||||||
GULF POWER CO | Senior Notes | Series 2013A Preference Stock [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Shares | shares | 500,000 | ||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Value | $ 50,000,000 | ||||||||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 5.60% | ||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Working Capital | 911,000,000 | 911,000,000 | |||||||||||||||||||||||||||||||
Long-term debt affiliated | 0 | 551,000,000 | 0 | 551,000,000 | |||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | $ 989,000,000 | $ 629,000,000 | $ 989,000,000 | $ 629,000,000 | |||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 334,210 | 334,210 | 334,210 | 334,210 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Promissory note | $ 0 | $ 0 | 301,000,000 | ||||||||||||||||||||||||||||||
Other long-term debt | $ 353,000,000 | $ 904,000,000 | 353,000,000 | 904,000,000 | |||||||||||||||||||||||||||||
Senior notes, current | 0 | 35,000,000 | 0 | 35,000,000 | |||||||||||||||||||||||||||||
Loans Payable to Bank, Current | 900,000,000 | 0 | 900,000,000 | 0 | |||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2017 | 900,000,000 | 900,000,000 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2019 | 125,000,000 | 125,000,000 | |||||||||||||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in 2021 | 270,000,000 | 270,000,000 | |||||||||||||||||||||||||||||||
2,018 | 50,000,000 | 50,000,000 | 50,000,000 | 50,000,000 | |||||||||||||||||||||||||||||
2,019 | 125,000,000 | 125,000,000 | 125,000,000 | 125,000,000 | |||||||||||||||||||||||||||||
Long-term debt, maturities, repayments of principal after year five | 630,000,000 | 630,000,000 | 630,000,000 | 630,000,000 | |||||||||||||||||||||||||||||
Bank loans | 900,000,000 | 1,200,000,000 | 900,000,000 | 1,200,000,000 | |||||||||||||||||||||||||||||
Bank loans outstanding | $ 900,000,000 | 1,200,000,000 | $ 900,000,000 | 1,200,000,000 | |||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | |||||||||||||||||||||||||||||||
Senior notes | $ 755,000,000 | 790,000,000 | $ 755,000,000 | 790,000,000 | |||||||||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 83,000,000 | 83,000,000 | 83,000,000 | 83,000,000 | |||||||||||||||||||||||||||||
Revenue bond obligations face value | $ 270,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.13% | ||||||||||||||||||||||||||||||||
Repayments of senior debt | 35,000,000 | 300,000,000 | 0 | ||||||||||||||||||||||||||||||
Period of nitrogen supply agreement | 20 years | ||||||||||||||||||||||||||||||||
Capitalized lease obligations | 0 | 74,000,000 | 0 | 74,000,000 | |||||||||||||||||||||||||||||
Capital leases, due 2017 | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||
Capital leases, due 2019 | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||
Capital leases, due 2020 | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||
Capital leases, due 2021 | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||
Capital leases, due 2022 | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||
Accumulated depreciation PPE | 1,325,000,000 | 1,289,000,000 | 1,325,000,000 | 1,289,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 100,000,000 | 100,000,000 | |||||||||||||||||||||||||||||||
Amount of variable rate pollution control revenue bonds outstanding requiring liquidity support | 40,000,000 | 40,000,000 | |||||||||||||||||||||||||||||||
Fixed Rate Pollution Control Revenue Bonds Outstanding, Amount Remarketed | 50,000,000 | 50,000,000 | |||||||||||||||||||||||||||||||
Pollution control revenue bonds | $ 40,000,000 | $ 40,000,000 | |||||||||||||||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | 100.00% | |||||||||||||||||||||||||||||||
Short-term debt | $ 4,000,000 | $ 23,000,000 | $ 4,000,000 | $ 23,000,000 | |||||||||||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | ||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 100,000,000 | $ 100,000,000 | |||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 100 | $ 100 | $ 100 | $ 100 | |||||||||||||||||||||||||||||
Temporary Equity, Shares Authorized | shares | 1,244,139 | 1,244,139 | 1,244,139 | 1,244,139 | |||||||||||||||||||||||||||||
Capitalized leases | $ 0 | $ 3,000,000 | $ 0 | $ 3,000,000 | |||||||||||||||||||||||||||||
Unamortized debt issuance expense | (1,000,000) | 0 | (1,000,000) | 0 | |||||||||||||||||||||||||||||
Revenue bonds, current | 50,000,000 | 50,000,000 | |||||||||||||||||||||||||||||||
Capital contributions from parent company | $ 1,000,000,000 | 1,002,000,000 | 627,000,000 | 277,000,000 | |||||||||||||||||||||||||||||
Expires, 2018 | 100,000,000 | 100,000,000 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 0 | 0 | |||||||||||||||||||||||||||||||
Assets | 4,866,000,000 | 8,235,000,000 | 4,866,000,000 | 8,235,000,000 | |||||||||||||||||||||||||||||
Unsecured debt, current | 900,000,000 | 900,000,000 | |||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in Year Three | 0 | 0 | |||||||||||||||||||||||||||||||
Long term debt and capital lease obligation maturities repayments in year five | 0 | 0 | |||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Kemper IGCC | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Capitalized lease obligations | $ 74,000,000 | $ 74,000,000 | |||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Plant Daniel Units 3 and 4 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Revenue bond obligations face value | 270,000,000 | ||||||||||||||||||||||||||||||||
Significant acquisitions and disposals, acquisition costs, assumption of debt, at fair value | $ 346,000,000 | ||||||||||||||||||||||||||||||||
Fair value adjustment at date of purchase | $ 76,000,000 | ||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Series 1999A | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.13% | ||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Promissory Notes | Promissory Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | $ 109,000,000 | 591,000,000 | |||||||||||||||||||||||||||||||
Debt instrument, face amount | 150,000,000 | ||||||||||||||||||||||||||||||||
Proceeds from Issuance of Debt | 40,000,000 | ||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Capital Lease Obligations | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.90% | 4.90% | |||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Redemption amount of principal notes | $ 300,000,000 | ||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Unsecured Debt | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 1,200,000,000 | ||||||||||||||||||||||||||||||||
MISSISSIPPI POWER CO | Unsecured Debt | Term Loan [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | 300,000,000 | ||||||||||||||||||||||||||||||||
Debt instrument, face amount | 1,200,000,000 | $ 1,200,000,000 | |||||||||||||||||||||||||||||||
SOUTHERN Co GAS | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 157,000,000 | $ 22,000,000 | 157,000,000 | $ 22,000,000 | |||||||||||||||||||||||||||||
Repayments of First Mortgage Bond | 0 | 0 | |||||||||||||||||||||||||||||||
2,022 | 93,000,000 | 93,000,000 | |||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Other long-term debt | 1,225,000,000 | 825,000,000 | 1,225,000,000 | 825,000,000 | |||||||||||||||||||||||||||||
2,018 | 155,000,000 | 155,000,000 | |||||||||||||||||||||||||||||||
2,019 | 350,000,000 | 350,000,000 | |||||||||||||||||||||||||||||||
Long-term debt, maturities, repayments of principal after year five | $ 4,600,000,000 | $ 4,600,000,000 | |||||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 70.00% | 70.00% | |||||||||||||||||||||||||||||||
Senior notes | $ 4,200,000,000 | 3,700,000,000 | $ 4,200,000,000 | 3,700,000,000 | |||||||||||||||||||||||||||||
Repayments of senior debt | 420,000,000 | 0 | |||||||||||||||||||||||||||||||
Accumulated depreciation PPE | 4,596,000,000 | 4,439,000,000 | 4,596,000,000 | 4,439,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 1,890,000,000 | 1,890,000,000 | |||||||||||||||||||||||||||||||
Short-term debt | 1,518,000,000 | 1,257,000,000 | 1,518,000,000 | 1,257,000,000 | |||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,900,000,000 | 1,900,000,000 | |||||||||||||||||||||||||||||||
2,020 | 0 | 0 | |||||||||||||||||||||||||||||||
2,021 | 330,000,000 | $ 330,000,000 | |||||||||||||||||||||||||||||||
Restrictions on payment of dividends to parent | 70.00% | ||||||||||||||||||||||||||||||||
Retained earnings, unappropriated | 719,000,000 | $ 719,000,000 | |||||||||||||||||||||||||||||||
Gas facility revenue bonds | 200,000,000 | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||||||||||||
Capital contributions from parent company | 1,085,000,000 | 103,000,000 | |||||||||||||||||||||||||||||||
Expires, 2018 | 0 | 0 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 0 | 0 | |||||||||||||||||||||||||||||||
Assets | 22,987,000,000 | 21,853,000,000 | 22,987,000,000 | 21,853,000,000 | |||||||||||||||||||||||||||||
SOUTHERN Co GAS | Medium-term Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
2,018 | 157,000,000 | 157,000,000 | |||||||||||||||||||||||||||||||
SOUTHERN Co GAS | First Mortgage Bonds And Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
2,018 | 22,000,000 | $ 22,000,000 | |||||||||||||||||||||||||||||||
SOUTHERN Co GAS | Gas Facility Revenue Bonds | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, number of series issued | series | 5 | ||||||||||||||||||||||||||||||||
Elizabeth Gas | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Gas facility revenue bonds | 180,000,000 | $ 180,000,000 | |||||||||||||||||||||||||||||||
Atlanta Gas Light | Medium-term Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | $ 22,000,000 | ||||||||||||||||||||||||||||||||
Long-term debt | $ 159,000,000 | 181,000,000 | $ 159,000,000 | 181,000,000 | |||||||||||||||||||||||||||||
Mississippi Power and Southern Power | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | |||||||||||||||||||||||||||||||
Southern Power and Traditional Operating Companies | Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 3,700,000,000 | $ 3,700,000,000 | |||||||||||||||||||||||||||||||
SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 770,000,000 | 560,000,000 | 770,000,000 | 560,000,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Line of credit facility, current borrowing capacity | 22,000,000 | 78,000,000 | 22,000,000 | 78,000,000 | |||||||||||||||||||||||||||||
2,018 | 770,000,000 | 770,000,000 | |||||||||||||||||||||||||||||||
2,019 | 600,000,000 | 600,000,000 | |||||||||||||||||||||||||||||||
Repayments of debt | 40,000,000 | ||||||||||||||||||||||||||||||||
Bank loans | $ 420,000,000 | 380,000,000 | $ 420,000,000 | 380,000,000 | |||||||||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | |||||||||||||||||||||||||||||||
Senior notes | $ 5,500,000,000 | 5,300,000,000 | $ 5,500,000,000 | 5,300,000,000 | |||||||||||||||||||||||||||||
Secured debt | 0 | 0 | |||||||||||||||||||||||||||||||
Repayments of senior debt | 500,000,000 | 200,000,000 | 525,000,000 | ||||||||||||||||||||||||||||||
Accumulated depreciation PPE | 1,910,000,000 | 1,484,000,000 | 1,910,000,000 | 1,484,000,000 | |||||||||||||||||||||||||||||
Unused credit with banks | 728,000,000 | 522,000,000 | 728,000,000 | 522,000,000 | |||||||||||||||||||||||||||||
Short-term debt | 105,000,000 | 209,000,000 | $ 105,000,000 | 209,000,000 | |||||||||||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | ||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 750,000,000 | $ 750,000,000 | 600,000,000 | ||||||||||||||||||||||||||||||
2,020 | 825,000,000 | 825,000,000 | |||||||||||||||||||||||||||||||
2,021 | 300,000,000 | 300,000,000 | |||||||||||||||||||||||||||||||
Capital contributions from parent company | 0 | 1,850,000,000 | $ 646,000,000 | ||||||||||||||||||||||||||||||
Expires, 2018 | 0 | 0 | |||||||||||||||||||||||||||||||
Line Of Credit Expire Year Three | 0 | 0 | |||||||||||||||||||||||||||||||
Assets | 15,206,000,000 | 15,169,000,000 | 15,206,000,000 | $ 15,169,000,000 | |||||||||||||||||||||||||||||
Long term debt and capital lease obligation maturities repayments in year five | 677,000,000 | 677,000,000 | |||||||||||||||||||||||||||||||
SOUTHERN POWER CO | Minimum | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||||||||||||||||
SOUTHERN POWER CO | Maximum | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||||||||||||||||
SOUTHERN POWER CO | Bank Loans, Current | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 420,000,000 | 60,000,000 | 420,000,000 | $ 60,000,000 | |||||||||||||||||||||||||||||
SOUTHERN POWER CO | Senior Notes, Current | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 350,000,000 | 500,000,000 | 350,000,000 | 500,000,000 | |||||||||||||||||||||||||||||
SOUTHERN POWER CO | Notes Payable to TRE | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Other Long-term Debt | 1,000,000 | 1,000,000 | |||||||||||||||||||||||||||||||
SOUTHERN POWER CO | Notes Payable to Banks [Member] | Floating Rate Bank Loan [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 100,000,000 | $ 100,000,000 | 100,000,000 | $ 60,000,000 | |||||||||||||||||||||||||||||
SOUTHERN POWER CO | Senior Notes | Floating Rate Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 525,000,000 | ||||||||||||||||||||||||||||||||
SOUTHERN POWER CO | Senior Notes | Series 2015D 1.85% Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Stock Redeemed or Called During Period, Shares | shares | 500,000,000 | ||||||||||||||||||||||||||||||||
SOUTHERN POWER CO | Senior Notes | Series 2017A [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.85% | ||||||||||||||||||||||||||||||||
Southern Company And Subsidiaries | Senior Notes | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | 4,000,000,000 | 4,000,000,000 | |||||||||||||||||||||||||||||||
Traditional Operating Companies | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 3,300,000,000 | 3,300,000,000 | 3,300,000,000 | 3,300,000,000 | |||||||||||||||||||||||||||||
Southern Company Gas Capital | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Line of Credit Terminated | $ 1,300,000,000 | ||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Unused credit with banks | 1,390,000,000 | 1,390,000,000 | |||||||||||||||||||||||||||||||
Expires, 2018 | 1,400,000,000 | ||||||||||||||||||||||||||||||||
Southern Company Gas Capital | First Mortgage Bonds Due 2026 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.40% | ||||||||||||||||||||||||||||||||
Southern Company Gas Capital | Senior Notes And Pollution Control Bond | Senior Notes Due 2076 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 450,000,000 | ||||||||||||||||||||||||||||||||
Nicor Gas | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Line of Credit Terminated | 700,000,000 | ||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Unused credit with banks | 500,000,000 | 500,000,000 | |||||||||||||||||||||||||||||||
First mortgage bonds | 1,000,000,000 | 625,000,000 | 1,000,000,000 | 625,000,000 | |||||||||||||||||||||||||||||
Expires, 2018 | $ 500,000,000 | ||||||||||||||||||||||||||||||||
Nicor Gas | First Mortgage Bonds Due 2027 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.03% | ||||||||||||||||||||||||||||||||
First mortgage bonds | $ 100,000,000 | ||||||||||||||||||||||||||||||||
Nicor Gas | First Mortgage Bonds Due 2037 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.62% | ||||||||||||||||||||||||||||||||
First mortgage bonds | $ 100,000,000 | ||||||||||||||||||||||||||||||||
Nicor Gas | First Mortgage Bonds Due 2047 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.85% | ||||||||||||||||||||||||||||||||
First mortgage bonds | $ 100,000,000 | ||||||||||||||||||||||||||||||||
Nicor Gas | First Mortgage Bonds Due 2057 | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.00% | ||||||||||||||||||||||||||||||||
First mortgage bonds | $ 100,000,000 | ||||||||||||||||||||||||||||||||
Southern Natural Gas Company, LLC | SOUTHERN Co GAS | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Ownership percentage, equity method investment | 50.00% | ||||||||||||||||||||||||||||||||
Capital Lease Obligations | GEORGIA POWER CO | Secured Debt | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Long-term debt | $ 154,000,000 | $ 169,000,000 | $ 154,000,000 | $ 169,000,000 | |||||||||||||||||||||||||||||
Redeemable Preferred Stock Type One [Member] | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 1,000,000 | 1,000,000 | 1,000,000 | 1,000,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 100 | $ 100 | $ 100 | $ 100 | |||||||||||||||||||||||||||||
Temporary Equity, Shares Authorized | shares | 20,000,000 | 20,000,000 | 20,000,000 | 20,000,000 | |||||||||||||||||||||||||||||
Redeemable Preferred Stock Type One [Member] | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 475,115 | 475,115 | 475,115 | 475,115 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 100 | $ 100 | $ 100 | $ 100 | |||||||||||||||||||||||||||||
Temporary Equity, Shares Authorized | shares | 3,850,000 | 3,850,000 | 3,850,000 | 3,850,000 | |||||||||||||||||||||||||||||
Redeemable Preferred Stock Type One [Member] | GULF POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Temporary Equity, Shares Authorized | shares | 0 | 0 | |||||||||||||||||||||||||||||||
Redeemable Preferred Stock Type Two [Member] | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 0 | 2,000,000 | 0 | 2,000,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 1 | $ 1 | $ 1 | $ 1 | |||||||||||||||||||||||||||||
Temporary Equity, Shares Authorized | shares | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | |||||||||||||||||||||||||||||
Redeemable Preferred Stock Type Two [Member] | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 10,000,000 | 1,520,000 | 10,000,000 | 1,520,000 | |||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 1 | $ 1 | $ 1 | $ 1 | |||||||||||||||||||||||||||||
Temporary Equity, Shares Authorized | shares | 27,500,000 | 27,500,000 | 27,500,000 | 27,500,000 | |||||||||||||||||||||||||||||
Redeemable Preferred Stock Type Two [Member] | GULF POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 0 | 0 | |||||||||||||||||||||||||||||||
Preferred Class A [Member] | GEORGIA POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preference stock, shares outstanding | shares | 0 | 0 | |||||||||||||||||||||||||||||||
5.00% Class A Preferred Stock | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 10,000,000 | 10,000,000 | 10,000,000 | ||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Temporary equity, dividend rate percentage | 0.05 | 0.0500 | |||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 1 | $ 1 | |||||||||||||||||||||||||||||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 25 | $ 25 | $ 25 | ||||||||||||||||||||||||||||||
5.00% Class A Preferred Stock | ALABAMA POWER CO | Aggregate Stated Capital [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 250,000,000 | ||||||||||||||||||||||||||||||||
5.30% Class A Preferred Stock | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 2,000,000 | ||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Temporary equity, dividend rate percentage | 0.065 | 0.0530 | |||||||||||||||||||||||||||||||
5.30% Class A Preferred Stock | ALABAMA POWER CO | Aggregate Stated Capital [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 50,000,000 | ||||||||||||||||||||||||||||||||
5.625% Preference Stock | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 6,000,000 | ||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Temporary equity, dividend rate percentage | 0.0645 | 0.05625 | |||||||||||||||||||||||||||||||
5.625% Preference Stock | ALABAMA POWER CO | Aggregate Stated Capital [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 150,000,000 | ||||||||||||||||||||||||||||||||
5.83% Class A Preferred Stock | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Temporary equity, shares outstanding (in shares) | shares | 1,500,000 | ||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Temporary equity, dividend rate percentage | 0.0583 | 0.0583 | |||||||||||||||||||||||||||||||
5.83% Class A Preferred Stock | ALABAMA POWER CO | Aggregate Stated Capital [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 38,000,000 | ||||||||||||||||||||||||||||||||
Preference Stock | GEORGIA POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preference stock, shares outstanding | shares | 0 | 0 | |||||||||||||||||||||||||||||||
Noncumulative Preferred Stock [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 25 | $ 25 | $ 25 | $ 25 | |||||||||||||||||||||||||||||
Preference stock, shares outstanding | shares | 0 | 2,000,000 | 0 | 2,000,000 | |||||||||||||||||||||||||||||
Noncumulative Preferred Stock [Member] | ALABAMA POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 25 | $ 25 | $ 25 | $ 25 | |||||||||||||||||||||||||||||
Preference stock, shares outstanding | shares | 0 | 8,000,000 | 0 | 8,000,000 | |||||||||||||||||||||||||||||
Noncumulative Preferred Stock [Member] | GULF POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Preference stock, shares outstanding | shares | 0 | 0 | |||||||||||||||||||||||||||||||
Loans Payable [Member] | MISSISSIPPI POWER CO | Bank Loans [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | $ 10,000,000 | ||||||||||||||||||||||||||||||||
Notes Payable to Banks [Member] | MISSISSIPPI POWER CO | Notes Payable to Banks [Member] | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Repayments of debt | $ 12,500,000 | ||||||||||||||||||||||||||||||||
Short Term Note [Member] | MISSISSIPPI POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Debt instrument, face amount | $ 9,000,000 | ||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.00% | ||||||||||||||||||||||||||||||||
Commercial Paper | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | $ 1,832,000,000 | $ 1,909,000,000 | $ 1,832,000,000 | $ 1,909,000,000 | |||||||||||||||||||||||||||||
Commercial Paper | GEORGIA POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 392,000,000 | 392,000,000 | |||||||||||||||||||||||||||||||
Commercial Paper | GULF POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 45,000,000 | 168,000,000 | 45,000,000 | 168,000,000 | |||||||||||||||||||||||||||||
Commercial Paper | MISSISSIPPI POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||
Commercial Paper | SOUTHERN Co GAS | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 1,518,000,000 | 1,257,000,000 | 1,518,000,000 | 1,257,000,000 | |||||||||||||||||||||||||||||
Commercial Paper | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 105,000,000 | 0 | 105,000,000 | 0 | |||||||||||||||||||||||||||||
Commercial Paper | Southern Company Gas Capital | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 1,243,000,000 | 733,000,000 | 1,243,000,000 | 733,000,000 | |||||||||||||||||||||||||||||
Commercial Paper | Nicor Gas | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Short term borrowings excluding other energy service contracts | 275,000,000 | 524,000,000 | 275,000,000 | 524,000,000 | |||||||||||||||||||||||||||||
Long-term Debt | Parent Company | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Bank loans | 1,500,000,000 | 2,000,000,000 | 1,500,000,000 | 2,000,000,000 | |||||||||||||||||||||||||||||
Short-term Debt | Parent Company | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Bank loans | 600,000,000 | 100,000,000 | 600,000,000 | 100,000,000 | |||||||||||||||||||||||||||||
Power Purchase Agreement | GEORGIA POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Capital leased assets, gross | 144,000,000 | 149,000,000 | 144,000,000 | 149,000,000 | |||||||||||||||||||||||||||||
Capitalized lease obligations | $ 132,000,000 | 141,000,000 | $ 132,000,000 | 141,000,000 | |||||||||||||||||||||||||||||
Capital leased assets, number of units | leased_asset_units | 2 | 2 | |||||||||||||||||||||||||||||||
Accumulated depreciation PPE | $ 29,000,000 | 19,000,000 | $ 29,000,000 | 19,000,000 | |||||||||||||||||||||||||||||
Power Purchase Agreement | GEORGIA POWER CO | Minimum | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 10.00% | 10.00% | |||||||||||||||||||||||||||||||
Power Purchase Agreement | GEORGIA POWER CO | Maximum | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 12.00% | 12.00% | |||||||||||||||||||||||||||||||
Line of Credit | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 2,000,000,000 | $ 2,000,000,000 | $ 1,250,000,000 | ||||||||||||||||||||||||||||||
FFB Loan | GEORGIA POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 2,600,000,000 | 2,600,000,000 | 2,600,000,000 | 2,600,000,000 | |||||||||||||||||||||||||||||
Continuing Letter of Credit Facility | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Unused credit with banks | 82,000,000 | 82,000,000 | |||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 120,000,000 | 120,000,000 | |||||||||||||||||||||||||||||||
Power Purchase Agreement | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Unused credit with banks | 19,000,000 | 19,000,000 | |||||||||||||||||||||||||||||||
Long-term Line of Credit | 101,000,000 | 101,000,000 | |||||||||||||||||||||||||||||||
Debt instrument, collateral amount | 113,000,000 | 113,000,000 | |||||||||||||||||||||||||||||||
Construction Loan And Bridge Loan | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Line of credit facility, current borrowing capacity | 0 | $ 209,000,000 | 0 | $ 209,000,000 | |||||||||||||||||||||||||||||
Debt, weighted average interest rate | 2.10% | 2.10% | |||||||||||||||||||||||||||||||
Southern Company Gas Capital | SOUTHERN Co GAS | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | 100.00% | |||||||||||||||||||||||||||||||
Parent Company | MISSISSIPPI POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Promissory note | $ 551,000,000 | 551,000,000 | |||||||||||||||||||||||||||||||
RE Roserock, LLC | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Percentage of voting interests acquired | 51.00% | ||||||||||||||||||||||||||||||||
Withholding of construction contract payments | 26,000,000 | $ 26,000,000 | |||||||||||||||||||||||||||||||
Mankato | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||||||||||||||||
Senior Lien | SOUTHERN POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Assets | $ 442,000,000 | $ 442,000,000 | |||||||||||||||||||||||||||||||
Chevron Products Company | MISSISSIPPI POWER CO | |||||||||||||||||||||||||||||||||
Financing (Textual) [Abstract] | |||||||||||||||||||||||||||||||||
Co-generation Assets, Net | $ 93,000,000 |
Financing - Scheduled Maturitie
Financing - Scheduled Maturities and Redemptions of Securities Due Within One Year (Details) | 1 Months Ended | 12 Months Ended | |||
Sep. 30, 2017USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares | Oct. 02, 2022$ / shares | Dec. 31, 2016USD ($)shares | Dec. 31, 2013 | |
Debt Disclosure [Line Items] | |||||
Unused credit with banks | $ 8,094,000,000 | ||||
2,019 | 3,074,000,000 | $ 3,076,000,000 | |||
2,020 | 2,273,000,000 | 1,326,000,000 | |||
2,021 | 2,643,000,000 | 2,655,000,000 | |||
Scheduled maturities and redemptions of securities due within one year | |||||
Senior notes | 2,354,000,000 | 1,995,000,000 | |||
Other long-term debt | 1,420,000,000 | 485,000,000 | |||
Revenue bonds | 90,000,000 | 76,000,000 | |||
Capitalized leases | 31,000,000 | 32,000,000 | |||
Unamortized debt issuance expense | (3,000,000) | (1,000,000) | |||
Total | 2,402,000,000 | 2,403,000,000 | |||
ALABAMA POWER CO | |||||
Debt Disclosure [Line Items] | |||||
Unused credit with banks | 1,335,000,000 | ||||
2,019 | 200,000,000 | 200,000,000 | |||
2,020 | 250,000,000 | 250,000,000 | |||
2,021 | $ 220,000,000 | 220,000,000 | |||
ALABAMA POWER CO | 4.92% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0492 | ||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100 | ||||
Temporary equity, shares outstanding (in shares) | shares | 80,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 103.23 | ||||
ALABAMA POWER CO | 4.72% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0472 | ||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100 | ||||
Temporary equity, shares outstanding (in shares) | shares | 50,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 102.18 | ||||
ALABAMA POWER CO | 4.64% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0464 | ||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100 | ||||
Temporary equity, shares outstanding (in shares) | shares | 60,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 103.14 | ||||
ALABAMA POWER CO | 4.60% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0460 | ||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100 | ||||
Temporary equity, shares outstanding (in shares) | shares | 100,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 104.20 | ||||
ALABAMA POWER CO | 4.52% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0452 | ||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100 | ||||
Temporary equity, shares outstanding (in shares) | shares | 50,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 102.93 | ||||
ALABAMA POWER CO | 4.20% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0420 | ||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100 | ||||
Temporary equity, shares outstanding (in shares) | shares | 135,115 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 105 | ||||
ALABAMA POWER CO | 5.00% Class A Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.05 | 0.0500 | |||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 25 | $ 25 | |||
Temporary equity, shares outstanding (in shares) | shares | 10,000,000 | 10,000,000 | |||
ALABAMA POWER CO | 5.83% Class A Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0583 | 0.0583 | |||
Temporary equity, shares outstanding (in shares) | shares | 1,500,000 | ||||
ALABAMA POWER CO | 6.450% Preference Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.06450 | ||||
ALABAMA POWER CO | 6.500% Preference Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.06500 | ||||
ALABAMA POWER CO | 5.30% Class A Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.065 | 0.0530 | |||
Temporary equity, shares outstanding (in shares) | shares | 2,000,000 | ||||
ALABAMA POWER CO | 5.625% Preference Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, dividend rate percentage | 0.0645 | 0.05625 | |||
Temporary equity, shares outstanding (in shares) | shares | 6,000,000 | ||||
GEORGIA POWER CO | |||||
Debt Disclosure [Line Items] | |||||
Unused credit with banks | $ 1,732,000,000 | ||||
2,019 | 499,000,000 | 500,000,000 | |||
2,020 | 950,000,000 | 0 | |||
2,021 | 325,000,000 | 325,000,000 | |||
Scheduled maturities and redemptions of securities due within one year | |||||
Senior notes | 750,000,000 | 450,000,000 | |||
Other long-term debt | 100,000,000 | 0 | |||
Capitalized leases | 11,000,000 | 10,000,000 | |||
Unamortized debt issuance expense | (1,000,000) | 0 | |||
Total | 860,000,000 | 460,000,000 | |||
Total | $ 747,000,000 | 748,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 2.00% | ||||
MISSISSIPPI POWER CO | |||||
Debt Disclosure [Line Items] | |||||
Unused credit with banks | $ 100,000,000 | ||||
2,019 | $ 125,000,000 | $ 125,000,000 | |||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary equity, shares outstanding (in shares) | shares | 334,210 | 334,210 | |||
Scheduled maturities and redemptions of securities due within one year | |||||
Long-term debt affiliated | $ 0 | $ 551,000,000 | |||
Senior notes | 0 | 35,000,000 | |||
Revenue bonds | 90,000,000 | 40,000,000 | |||
Capitalized leases | 0 | 3,000,000 | |||
Unamortized debt issuance expense | (1,000,000) | 0 | |||
Total | 50,000,000 | 50,000,000 | |||
Revenue bonds, current | 50,000,000 | ||||
Long term debt and capital lease obligation maturities repayments in year five | 0 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 7.13% | ||||
Long-term Pollution Control Bond, Current | $ 40,000,000 | ||||
MISSISSIPPI POWER CO | 4.40% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100,000,000 | ||||
Temporary equity, shares outstanding (in shares) | shares | 8,867,000,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 104.32 | ||||
MISSISSIPPI POWER CO | 4.72% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100,000,000 | ||||
Temporary equity, shares outstanding (in shares) | shares | 16,700,000,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 102.25 | ||||
MISSISSIPPI POWER CO | 4.60% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100,000,000 | ||||
Temporary equity, shares outstanding (in shares) | shares | 8,643,000,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 107 | ||||
MISSISSIPPI POWER CO | 5.25% Redeemable Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par value/stated capital per share (in dollars per share) | $ / shares | $ 100,000,000 | ||||
Temporary equity, shares outstanding (in shares) | shares | 300,000,000,000 | ||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 100 | ||||
SOUTHERN POWER CO | |||||
Debt Disclosure [Line Items] | |||||
Unused credit with banks | $ 728,000,000 | $ 522,000,000 | |||
Repayments of debt | $ 40,000,000 | ||||
2,019 | 600,000,000 | ||||
2,020 | 825,000,000 | ||||
2,021 | 300,000,000 | ||||
Scheduled maturities and redemptions of securities due within one year | |||||
Total | 770,000,000 | ||||
Long term debt and capital lease obligation maturities repayments in year five | 677,000,000 | ||||
SOUTHERN Co GAS | |||||
Debt Disclosure [Line Items] | |||||
Unused credit with banks | 1,890,000,000 | ||||
2,019 | 350,000,000 | ||||
2,020 | 0 | ||||
2,021 | 330,000,000 | ||||
Scheduled maturities and redemptions of securities due within one year | |||||
Total | 155,000,000 | ||||
Medium-term Notes | SOUTHERN Co GAS | |||||
Scheduled maturities and redemptions of securities due within one year | |||||
Total | $ 157,000,000 | ||||
Scenario, Forecast | ALABAMA POWER CO | 5.00% Class A Preferred Stock | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redemption Price Per Share (in dollars per share) | $ / shares | $ 25.50 |
Financing - Committed Credit Ar
Financing - Committed Credit Arrangements With Banks (Details) - USD ($) | Dec. 31, 2017 | Nov. 30, 2017 | Sep. 30, 2017 | May 31, 2017 | Apr. 30, 2017 | Dec. 31, 2016 |
Credit arrangements by company | ||||||
Expires, 2018 | $ 195,000,000 | |||||
Expires, 2019 | 25,000,000 | |||||
Expires, 2020 | 725,000,000 | |||||
Expires, 2022 | 7,200,000,000 | |||||
Total | 8,145,000,000 | |||||
Unused | 8,094,000,000 | |||||
Executable term-loans, one year | 65,000,000 | |||||
Executable term-loans, two years | 0 | |||||
Due within one year, term out | 40,000,000 | |||||
Due within one year, no term out | 155,000,000 | |||||
Parent Company | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 0 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 0 | |||||
Expires, 2022 | 2,000,000,000 | |||||
Total | 2,000,000,000 | |||||
Unused | 1,999,000,000 | |||||
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 CO | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 35,000,000 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 500,000,000 | $ 500,000,000 | ||||
Expires, 2022 | 800,000,000 | |||||
Total | 1,335,000,000 | |||||
Unused | 1,335,000,000 | |||||
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 | 35,000,000 | |||||
GEORGIA POWER CO | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 0 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 0 | |||||
Expires, 2022 | 1,750,000,000 | |||||
Total | 1,750,000,000 | |||||
Unused | 1,732,000,000 | |||||
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 | |||||
GULF POWER CO | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 30,000,000 | |||||
Expires, 2019 | 25,000,000 | |||||
Expires, 2020 | 225,000,000 | |||||
Expires, 2022 | 0 | |||||
Total | 280,000,000 | $ 195,000,000 | ||||
Unused | 280,000,000 | |||||
Executable term-loans, one year | 45,000,000 | |||||
Executable term-loans, two years | 0 | |||||
Due within one year, term out | 20,000,000 | |||||
Due within one year, no term out | 10,000,000 | |||||
SOUTHERN Co GAS | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 0 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 0 | |||||
Expires, 2022 | 1,900,000,000 | |||||
Total | 1,900,000,000 | |||||
Unused | 1,890,000,000 | |||||
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 | |||||
MISSISSIPPI POWER CO | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 100,000,000 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 0 | |||||
Expires, 2022 | 0 | |||||
Total | 100,000,000 | |||||
Unused | 100,000,000 | |||||
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 | 100,000,000 | |||||
SOUTHERN POWER CO | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 0 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 0 | |||||
Expires, 2022 | 750,000,000 | |||||
Total | 750,000,000 | $ 600,000,000 | ||||
Unused | 728,000,000 | $ 522,000,000 | ||||
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 | |||||
Southern Company Gas Capital | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | $ 1,400,000,000 | |||||
Expires, 2022 | 1,400,000,000 | |||||
Unused | 1,390,000,000 | |||||
Nicor Gas | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | $ 500,000,000 | |||||
Expires, 2022 | 500,000,000 | |||||
Unused | 500,000,000 | |||||
Other Subsidiaries | ||||||
Credit arrangements by company | ||||||
Expires, 2018 | 30,000,000 | |||||
Expires, 2019 | 0 | |||||
Expires, 2020 | 0 | |||||
Expires, 2022 | 0 | |||||
Total | 30,000,000 | |||||
Unused | 30,000,000 | |||||
Executable term-loans, one year | 20,000,000 | |||||
Executable term-loans, two years | 0 | |||||
Due within one year, term out | 20,000,000 | |||||
Due within one year, no term out | 10,000,000 | |||||
Continuing Letter of Credit Facility | SOUTHERN POWER CO | ||||||
Credit arrangements by company | ||||||
Total | 120,000,000 | |||||
Unused | $ 82,000,000 |
Financing - Short-term Borrowin
Financing - Short-term Borrowings (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 2,439,000,000 | $ 2,032,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 1.90% | 1.10% |
Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 1,832,000,000 | $ 1,909,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 1.80% | 1.10% |
Short-term bank debt | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 607,000,000 | $ 123,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 2.30% | 1.70% |
Southern Company Gas Capital | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 1,243,000,000 | $ 733,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 1.73% | 1.09% |
GEORGIA POWER CO | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 392,000,000 | |
Short-term debt at the end of the period, weighted average interest rate | 1.10% | |
GEORGIA POWER CO | Short-term bank debt | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 150,000,000 | |
Short-term debt at the end of the period, weighted average interest rate | 2.1918% | |
GULF POWER CO | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 268,000,000 | |
Short-term debt at the end of the period, weighted average interest rate | 1.20% | |
GULF POWER CO | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 45,000,000 | $ 168,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 2.00% | 1.10% |
GULF POWER CO | Short-term bank debt | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 100,000,000 | |
Short-term debt at the end of the period, weighted average interest rate | 1.50% | |
MISSISSIPPI POWER CO | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 0 | $ 0 |
SOUTHERN POWER CO | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 105,000,000 | 0 |
Short-term debt at the end of the period, weighted average interest rate | 2.00% | |
Nicor Gas | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 275,000,000 | $ 524,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 1.83% | 0.95% |
SOUTHERN Co GAS | Commercial Paper | ||
Short-term borrowings | ||
Short term borrowings excluding other energy service contracts | $ 1,518,000,000 | $ 1,257,000,000 |
Short-term debt at the end of the period, weighted average interest rate | 1.75% | 1.03% |
Financing - Schedule of Borrowi
Financing - Schedule of Borrowings Under FFB Credit Facility (Details) | Dec. 31, 2017 |
GEORGIA POWER CO | |
Line of Credit Facility [Line Items] | |
Fixed stated interest rate of debt obligation | 2.00% |
Financing - Schedule Of Credit
Financing - Schedule Of Credit Arrangements With Project Credit Facilities (Details) - USD ($) | Dec. 31, 2017 | Apr. 30, 2017 | Dec. 31, 2016 |
Line of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | $ 8,145,000,000 | ||
Line of credit facility, remaining borrowing capacity | 8,094,000,000 | ||
SOUTHERN POWER CO | |||
Line of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | 750,000,000 | $ 600,000,000 | |
Line of credit facility, remaining borrowing capacity | 728,000,000 | $ 522,000,000 | |
SOUTHERN POWER CO | RE Roserock Holdings, LLC | Construction Loan Facility | |||
Line of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | 63,000,000 | ||
SOUTHERN POWER CO | RE Roserock Holdings, LLC | Bridge Loan | |||
Line of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | 180,000,000 | ||
SOUTHERN POWER CO | RE Roserock Holdings, LLC | Construction Loan And Bridge Loan | |||
Line of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | 243,000,000 | ||
Line of credit facility, remaining borrowing capacity | 34,000,000 | ||
SOUTHERN POWER CO | RE Roserock Holdings, LLC | Letter of Credit | |||
Line of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | 23,000,000 | ||
Line of credit facility, remaining borrowing capacity | $ 16,000,000 |
Financing - Outstanding Classes
Financing - Outstanding Classes of Capital Stock (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Increase (Decrease) in Temporary Equity [Roll Forward] | |||
Beginning balance | $ 118 | ||
Redeemed | (658) | $ 0 | $ (412) |
Ending balance | $ 324 | $ 118 | |
MISSISSIPPI POWER CO | |||
Increase (Decrease) in Temporary Equity [Roll Forward] | |||
Temporary equity, shares outstanding (in shares) | 334,210 | 334,210 | |
Dividend rate, maximum | 5.25% | 5.25% | |
Redeemable Preferred Stock | |||
Increase (Decrease) in Temporary Equity [Roll Forward] | |||
Beginning balance | $ 118 | $ 118 | 375 |
Issued | 250 | 0 | 0 |
Redeemed | (38) | 0 | (262) |
Issuance Costs | (6) | 5 | |
Ending balance | $ 324 | $ 118 | $ 118 |
Depositary Shares | MISSISSIPPI POWER CO | |||
Increase (Decrease) in Temporary Equity [Roll Forward] | |||
Temporary equity, shares outstanding (in shares) | 1,200,000,000,000 |
Common Stock and Stock Compe111
Common Stock and Stock Compensation - Textual Stock Issued, Reserved, Employee (Details) $ / shares in Units, shares in Thousands, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Jan. 31, 2017USD ($) | Dec. 31, 2016USD ($)shares | Dec. 31, 2017USD ($)goalEmployeeshares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($)shares | Jul. 01, 2016$ / shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of Performance Goals | goal | 3 | |||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Number of employees participating in restricted stock unit and performance share units program | Employee | 327 | |||||
Common stock | $ | $ 793 | $ 3,758 | $ 256 | |||
Common stock fees and commissions | $ | $ 1.1 | |||||
Stock issued employee and director stock plans | 14,600 | |||||
Proceeds from issuance of shares under share-based compensation plans | $ | $ 659 | |||||
Number of shares reserved for issuance to stock-based compensation plan | 71,000 | |||||
Number of employees participating in stock-based compensation plans | Employee | 5,112 | |||||
Common Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock issued (in shares) | 17,319 | 76,140 | 6,571 | |||
Treasury | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock issued (in shares) | 0 | 2,599 | 2,599 | |||
At-The-Market | Common Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock issued (in shares) | 2,700 | |||||
Common stock | $ | $ 134 | |||||
Southern Company Common Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Remaining shares available for awards | 13,000 | |||||
ALABAMA POWER CO | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Number of employees participating in stock-based compensation plans | Employee | 793 | |||||
GEORGIA POWER CO | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Vesting period of performance share units issued under performance share plan | 3 years | |||||
Number of employees participating in stock-based compensation plans | Employee | 895 | |||||
GULF POWER CO | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Vesting period of performance share units issued under performance share plan | 3 years | |||||
Common stock | $ | $ 175 | $ 175 | $ 0 | $ 20 | ||
Number of employees participating in stock-based compensation plans | Employee | 168 | |||||
GULF POWER CO | Common Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock issued (in shares) | 0 | 1,000 | ||||
MISSISSIPPI POWER CO | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period of performance share units issued under performance share plan | 3 years | |||||
Number of employees participating in stock-based compensation plans | Employee | 180 | |||||
SOUTHERN Co GAS | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Southern Company | SOUTHERN Co GAS | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Business acquisition share price (in dollars per share) | $ / shares | $ 66 |
Common Stock and Stock Compe112
Common Stock and Stock Compensation - Textual Stock Options (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average remaining contractual term for options outstanding | 5 years | ||
Weighted average remaining contractual term for options exercisable | 0 years | ||
Aggregate intrinsic value for options outstanding | $ 119,000,000 | ||
Aggregate intrinsic value for options exercisable | 0 | ||
Total compensation cost for award recognized in income, tax benefit | 4,000,000 | ||
Total intrinsic value of options exercised | 64,000,000 | $ 120,000,000 | $ 48,000,000 |
Actual tax benefit for the tax deduction from stock option exercised | 25,000,000 | 46,000,000 | 19,000,000 |
Cash received from issuance related to option exercise | $ 239,000,000 | $ 448,000,000 | $ 154,000,000 |
Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share Based Compensation Arrangement by Share Based Payment Award Award Expiration Period | 3 years | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 600,000 | ||
Total compensation cost for award recognized in income | $ 25,000,000 | ||
Total compensation cost for award recognized in income, tax benefit | $ 10,000,000 | ||
ROE-based Portion Of The Stock Compensation Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage of total performance share units granted | 25.00% | 25.00% | 25.00% |
EPS-based Portion Of The Performance Share Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage of total performance share units granted | 20.00% | 25.00% | 25.00% |
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share Based Compensation Arrangement by Share Based Payment Award Award Expiration Period | 10 years | ||
TSR-based Portion Of The Stock Compensation Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage of total performance share units granted | 30.00% | 50.00% | 50.00% |
ALABAMA POWER CO | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Aggregate intrinsic value for options outstanding | $ 17,000,000 | ||
Total intrinsic value of options exercised | 12,000,000 | $ 21,000,000 | $ 8,000,000 |
Actual tax benefit for the tax deduction from stock option exercised | 5,000,000 | 8,000,000 | 3,000,000 |
Cash received from issuance related to option exercise | $ 0 | ||
ALABAMA POWER CO | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 58,001 | ||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.21 | ||
Total compensation cost for award recognized in income | $ 3,000,000 | ||
Total compensation cost for award recognized in income, tax benefit | 1,000,000 | ||
GEORGIA POWER CO | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Aggregate intrinsic value for options outstanding | 30,000,000 | ||
Total intrinsic value of options exercised | 13,000,000 | 18,000,000 | 9,000,000 |
Actual tax benefit for the tax deduction from stock option exercised | 5,000,000 | 7,000,000 | 4,000,000 |
Cash received from issuance related to option exercise | $ 0 | ||
GEORGIA POWER CO | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 59,218 | ||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | ||
Total compensation cost for award recognized in income | $ 3,000,000 | ||
Total compensation cost for award recognized in income, tax benefit | 1,000,000 | ||
GULF POWER CO | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Aggregate intrinsic value for options outstanding | 3,000,000 | ||
Total intrinsic value of options exercised | 2,000,000 | 3,000,000 | 2,000,000 |
Cash received from issuance related to option exercise | $ 0 | ||
GULF POWER CO | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 15,736 | ||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 48.88 | ||
MISSISSIPPI POWER CO | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 13,260 | ||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | ||
MISSISSIPPI POWER CO | Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Aggregate intrinsic value for options outstanding | $ 4,000,000 | ||
Total intrinsic value of options exercised | 2,000,000 | 4,000,000 | 3,000,000 |
Actual tax benefit for the tax deduction from stock option exercised | 1,000,000 | $ 2,000,000 | $ 1,000,000 |
Cash received from issuance related to option exercise | $ 0 |
Common Stock and Stock Compe113
Common Stock and Stock Compensation - Table Stock Option Activity (Details) - $ / shares shares in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | ||
Outstanding at December 31, 2016 | 18.6 | 24.6 |
Exercised | 6 | |
Cancelled | 0 | |
Outstanding and Exercisable at December 31, 2017 | 18.6 | |
Weighted Average Exercise Price | ||
Outstanding at December 31, 2016 | $ 41.68 | $ 41.28 |
Cancelled | 39.90 | |
Exercised | 40.03 | |
Outstanding and Exercisable at December 31, 2017 | $ 41.68 |
Common Stock and Stock Compe114
Common Stock and Stock Compensation - Textual Performance Shares (Details) - USD ($) $ / shares in Units, $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Aggregate intrinsic value for options exercisable | $ 0 | ||||
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% | ||||
Total compensation cost for award recognized in income, tax benefit | $ 4 | ||||
EPS-based and ROE-based Performance Share Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 100.00% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.21 | $ 48.87 | $ 47.75 | ||
ROE-based Portion Of The Stock Compensation Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Percentage of total performance share units granted | 25.00% | 25.00% | 25.00% | ||
Share based compensation, target grant fair value | 20.00% | ||||
EPS-based Portion Of The Performance Share Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Percentage of total performance share units granted | 20.00% | 25.00% | 25.00% | ||
Share based compensation, target grant fair value | 20.00% | ||||
TSR-based Portion Of The Stock Compensation Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Percentage of total performance share units granted | 30.00% | 50.00% | 50.00% | ||
Share based compensation, target grant fair value | 30.00% | ||||
EPS-based Portion Of The Stock Compensation Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Percentage of total performance share units granted | 20.00% | 25.00% | 25.00% | ||
Restricted Stock Portion Of The Stock Compensation Plan [Member] [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Percentage of total performance share units granted | 30.00% | ||||
Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share based compensation, target grant fair value | 30.00% | ||||
Performance share units, unvested (in shares) | 700,000 | ||||
Equity instrument, granted (in shares) | 600,000 | ||||
Equity instruments, vested (in shares) | 100,000 | ||||
Total compensation cost for award recognized in income | $ 25 | ||||
Total compensation cost for award recognized in income, tax benefit | 10 | ||||
Total unrecognized compensation cost related to award | $ 8 | ||||
Total unrecognized compensation cost related to award, weighted average period | 13 months | ||||
Share Based Compensation Arrangement by Share Based Payment Award Award Expiration Period | 3 years | ||||
Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of performance share units issued under performance share plan | 3 years | ||||
Initial assumed percentage payout at end of performance period | 100.00% | ||||
Performance share units, unvested (in shares) | 3,240,000 | 2,890,000 | 3,240,000 | ||
Equity instrument, granted (in shares) | 1,220,000 | ||||
Equity instruments, vested (in shares) | 1,500,000 | ||||
Total compensation cost for award recognized in income | $ 74 | $ 96 | $ 88 | ||
Total compensation cost for award recognized in income, tax benefit | 29 | $ 37 | $ 34 | ||
Total unrecognized compensation cost related to award | $ 30 | ||||
Total unrecognized compensation cost related to award, weighted average period | 21 months | ||||
ALABAMA POWER CO | EPS-based and ROE-based Performance Share Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 100.00% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.21 | $ 48.86 | $ 47.78 | ||
ALABAMA POWER CO | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.21 | ||||
Equity instrument, granted (in shares) | 58,001 | ||||
Total compensation cost for award recognized in income | $ 3 | ||||
Total compensation cost for award recognized in income, tax benefit | $ 1 | ||||
ALABAMA POWER CO | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
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% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.07 | $ 45.15 | $ 46.42 | ||
Equity instrument, granted (in shares) | 135,502 | 249,065 | 214,709 | ||
Total compensation cost for award recognized in income | $ 9 | $ 15 | $ 13 | ||
Total compensation cost for award recognized in income, tax benefit | 4 | $ 6 | $ 5 | ||
Total unrecognized compensation cost related to award | $ 2 | ||||
Total unrecognized compensation cost related to award, weighted average period | 21 months | ||||
SOUTHERN Co GAS | EPS-based and ROE-based Performance Share Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | ||||
SOUTHERN Co GAS | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.23 | ||||
Equity instrument, granted (in shares) | 25,166 | 109,969 | 47,546 | ||
Total compensation cost for award recognized in income | $ 4 | ||||
Total compensation cost for award recognized in income, tax benefit | 2 | ||||
Compensation not yet recognized | $ 1 | ||||
Total unrecognized compensation cost related to award, weighted average period | 13 months | ||||
Award requisite service period | 3 years | ||||
SOUTHERN Co GAS | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.27 | ||||
Equity instrument, granted (in shares) | 300,000 | ||||
Total compensation cost for award recognized in income | $ 8 | ||||
Total compensation cost for award recognized in income, tax benefit | 3 | ||||
Total unrecognized compensation cost related to award | $ 6 | ||||
Total unrecognized compensation cost related to award, weighted average period | 21 months | ||||
SOUTHERN Co GAS | Restricted Stock Units (RSUs), Pre-acquisition [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total compensation cost for award recognized in income | $ 13 | $ 8 | |||
Total compensation cost for award recognized in income, tax benefit | $ 4 | 4 | |||
Total unrecognized compensation cost related to award | $ 3 | ||||
Total unrecognized compensation cost related to award, weighted average period | 12 months | ||||
GEORGIA POWER CO | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
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 CO | EPS-based and ROE-based Performance Share Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 100.00% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | $ 48.84 | $ 47.78 | ||
GEORGIA POWER CO | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | ||||
Equity instrument, granted (in shares) | 59,218 | ||||
Total compensation cost for award recognized in income | $ 3 | ||||
Total compensation cost for award recognized in income, tax benefit | 1 | ||||
Total unrecognized compensation cost related to award | $ 1 | ||||
Total unrecognized compensation cost related to award, weighted average period | 13 months | ||||
GEORGIA POWER CO | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.27 | $ 45.17 | $ 46.41 | ||
Equity instrument, granted (in shares) | 138,102 | 261,434 | 236,804 | ||
Total compensation cost for award recognized in income | $ 10 | $ 15 | $ 15 | ||
Total compensation cost for award recognized in income, tax benefit | 4 | $ 6 | $ 6 | ||
Total unrecognized compensation cost related to award | $ 3 | ||||
Total unrecognized compensation cost related to award, weighted average period | 21 months | ||||
GULF POWER CO | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
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 CO | EPS-based and ROE-based Performance Share Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 100.00% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.18 | $ 48.83 | $ 47.75 | ||
GULF POWER CO | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 48.88 | ||||
Equity instrument, granted (in shares) | 15,736 | ||||
GULF POWER CO | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument, granted (in shares) | 28,423 | 57,333 | 48,962 | ||
Fair value assumptions weighted average grant date fair value (in dollars per share) | $ 47.30 | $ 45.18 | $ 46.38 | ||
MISSISSIPPI POWER CO | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of performance share units issued under performance share plan | 3 years | ||||
MISSISSIPPI POWER CO | EPS-based and ROE-based Performance Share Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 100.00% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | 48.84 | 47.77 | ||
MISSISSIPPI POWER CO | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.22 | ||||
Equity instrument, granted (in shares) | 13,260 | ||||
MISSISSIPPI POWER CO | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
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% | ||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 49.24 | $ 45.17 | $ 46.41 | ||
Equity instrument, granted (in shares) | 30,933 | 62,435 | 53,909 | ||
Total compensation cost for award recognized in income | $ 2 | $ 4 | $ 4 | ||
Total compensation cost for award recognized in income, tax benefit | $ 1 | $ 1 | $ 2 | ||
Minimum | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 0.00% | ||||
Maximum | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Initial assumed percentage payout at end of performance period | 200.00% | ||||
Parent Company | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ 53.83 | $ 49.25 | |||
Equity instrument, granted (in shares) | 742,461 | ||||
Total compensation cost for award recognized in income | $ 12 |
Common Stock and Stock Compe115
Common Stock and Stock Compensation - Table Performance Shares, Assumptions Used (Details) - Performance Shares - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected volatility | 15.60% | 15.00% | 12.90% |
Expected term (in years) | 3 years | 3 years | 3 years |
Interest rate | 1.40% | 0.80% | 1.00% |
Weighted average grant-date fair value (in dollars per share) | $ 49.08 | $ 45.06 | $ 46.38 |
Vesting period of performance share units issued under performance share plan | 3 years |
Common Stock and Stock Compe116
Common Stock and Stock Compensation - Textual Southern Company Gas Awards (Details) | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016USD ($)$ / sharesshares | Jun. 30, 2016USD ($)shares | Dec. 31, 2017USD ($)performance_measure$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Jul. 01, 2016$ / shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Tax credit carryforward | $ 2,100,000,000 | |||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Proceeds from stock options exercised | $ 239,000,000 | $ 448,000,000 | $ 154,000,000 | |||
Aggregate intrinsic value for options outstanding | 119,000,000 | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 4,000,000 | |||||
Restricted Stock Units (RSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 600,000 | |||||
Performance share units, unvested (in shares) | shares | 700,000 | |||||
Total compensation cost for award recognized in income | $ 25,000,000 | |||||
Total unrecognized compensation cost related to award, weighted average period | 13 months | |||||
Equity instruments, vested (in shares) | shares | 100,000 | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 10,000,000 | |||||
Performance Shares | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 1,220,000 | |||||
Performance share units, unvested (in shares) | shares | 3,240,000 | 2,890,000 | 3,240,000 | |||
Total compensation cost for award recognized in income | $ 74,000,000 | $ 96,000,000 | 88,000,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 21 months | |||||
Equity instruments, vested (in shares) | shares | 1,500,000 | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 29,000,000 | $ 37,000,000 | $ 34,000,000 | |||
Parent Company | Restricted Stock Units (RSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 742,461 | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares | $ 53.83 | $ 49.25 | ||||
Merger-related expenses | $ 13,000,000 | |||||
Total compensation cost for award recognized in income | $ 12,000,000 | |||||
ALABAMA POWER CO | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
Proceeds from stock options exercised | $ 0 | |||||
Aggregate intrinsic value for options outstanding | $ 17,000,000 | |||||
ALABAMA POWER CO | Restricted Stock Units (RSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 58,001 | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares | $ 49.21 | |||||
Total compensation cost for award recognized in income | $ 3,000,000 | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 1,000,000 | |||||
ALABAMA POWER CO | Performance Shares | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 135,502 | 249,065 | 214,709 | |||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares | $ 49.07 | $ 45.15 | $ 46.42 | |||
Total compensation cost for award recognized in income | $ 9,000,000 | $ 15,000,000 | $ 13,000,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 21 months | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 4,000,000 | $ 6,000,000 | 5,000,000 | |||
SOUTHERN Co GAS | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Merger-related expenses | $ 41,000,000 | $ 0 | ||||
Shares vested and issued each year employee remains in service | 33.00% | |||||
SOUTHERN Co GAS | Restricted Stock Units (RSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Award requisite service period | 3 years | |||||
Equity instrument, granted (in shares) | shares | 25,166 | 109,969 | 47,546 | |||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares | $ 49.23 | |||||
Total compensation cost for award recognized in income | $ 4,000,000 | |||||
Compensation not yet recognized | $ 1,000,000 | |||||
Total unrecognized compensation cost related to award, weighted average period | 13 months | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 2,000,000 | |||||
SOUTHERN Co GAS | Change In Control Awards | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Total compensation cost for award recognized in income | 4,000,000 | 12,000,000 | ||||
Tax credit carryforward | $ 1,000,000 | 6,000,000 | $ 1,000,000 | |||
Compensation not yet recognized | $ 8,000,000 | |||||
Total unrecognized compensation cost related to award, weighted average period | 18 months | |||||
SOUTHERN Co GAS | Stock Options | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Award requisite service period | 3 years | |||||
Expiration period | 10 years | |||||
SOUTHERN Co GAS | Performance Shares | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 300,000 | |||||
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares | $ 49.27 | |||||
Total compensation cost for award recognized in income | $ 8,000,000 | |||||
Total unrecognized compensation cost related to award, weighted average period | 21 months | |||||
Number of performance criteria | performance_measure | 2 | |||||
Performance measure one, % of award | 75.00% | |||||
Performance measure two, % of award | 25.00% | |||||
Performance period | 3 years | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 3,000,000 | |||||
SOUTHERN Co GAS | Restricted Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Equity instrument, granted (in shares) | shares | 303,618 | |||||
Performance share units, unvested (in shares) | shares | 398,832 | 398,832 | ||||
Equity instruments, vested (in shares) | shares | 699,960 | |||||
SOUTHERN Co GAS | Predecessor | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Merger-related expenses | $ 56,000,000 | $ 44,000,000 | ||||
Compensation not yet recognized | $ 0 | $ 0 | ||||
Aggregate intrinsic value for options outstanding | $ 13,000,000 | 3,000,000 | 13,000,000 | |||
SOUTHERN Co GAS | Predecessor | Cash and Stock-based Awards | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Total compensation cost for award recognized in income | $ 24,000,000 | $ 40,000,000 | ||||
SOUTHERN Co GAS | Minimum | Change In Control Awards | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Percentage of shares to common stock based on price metrics and performance goals | 0.00% | |||||
SOUTHERN Co GAS | Maximum | Change In Control Awards | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Percentage of shares to common stock based on price metrics and performance goals | 100.00% | |||||
Southern Company | SOUTHERN Co GAS | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Business acquisition share price (in dollars per share) | $ / shares | $ 66 | |||||
Conversion ratio, percentage of underlying stock award units | 125.00% |
Common Stock and Stock Compe117
Common Stock and Stock Compensation - Table Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Earnings per share (EPS) — | |||
As reported shares | 1,000 | 951 | 910 |
Effect of options | 8 | 7 | 4 |
Diluted shares | 1,008 | 958 | 914 |
Common Stock and Stock Compe118
Common Stock and Stock Compensation - Textual Dividend Restrictions (Details) $ in Billions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Equity [Abstract] | |
Undistributed retained earnings of the subsidiaries | $ 5.3 |
Nuclear Insurance (Details)
Nuclear Insurance (Details) | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Jointly Owned Utility Plant Interests [Line Items] | |
Maximum fund for public liability claims arising from a single nuclear incident under price-anderson amendments act | $ 13,400,000,000 |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 450,000,000 |
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 |
Aggregate payment for claims resulting from terrorist acts in one year period | 3,200,000,000 |
Vogtle Units 3 and 4 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Maximum limits for accidental property damage occurring during construction | 2,750,000,000 |
ALABAMA POWER CO | |
Jointly Owned Utility Plant Interests [Line Items] | |
Maximum fund for public liability claims arising from a single nuclear incident under price-anderson amendments act | 13,400,000,000 |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 450,000,000 |
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 |
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 deductible waiting period | 26 weeks |
Maximum coverage per occurrence per unit limit to obtain replacement power | $ 490,000,000 |
Current maximum annual assessments under NEIL policies | 55,000,000 |
Aggregate payment for claims resulting from terrorist acts in one year period | $ 3,200,000,000 |
Elected deductible waiting period, days | 84 days |
Maximum sublimit non-nuclear losses | $ 750,000,000 |
Maximum deductible waiting period days | 182 days |
GEORGIA POWER CO | |
Jointly Owned Utility Plant Interests [Line Items] | |
Maximum fund for public liability claims arising from a single nuclear incident under price-anderson amendments act | $ 13,400,000,000 |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 450,000,000 |
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 |
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 deductible waiting period | 26 weeks |
Maximum coverage per occurrence per unit limit to obtain replacement power | $ 490,000,000 |
Elected deductible waiting period | 12-week |
Current maximum annual assessments under NEIL policies | $ 81,000,000 |
Aggregate payment for claims resulting from terrorist acts in one year period | $ 3,200,000,000 |
Block period considered for inflation adjustment against maximum yearly assessment | 5 years |
Maximum sublimit non-nuclear losses | $ 750,000,000 |
GEORGIA POWER CO | Vogtle Units 3 and 4 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Maximum limits for accidental property damage occurring during construction | 2,750,000,000 |
Alabama Power and Georgia Power | |
Jointly Owned Utility Plant Interests [Line Items] | |
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 Additional Coverage Provided For Losses Under Excess Insurance, Non-Nuclear Losses | $ 750,000,000 |
Elected deductible waiting period | 12-week |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Liabilities: | ||
Weather derivative premium | $ 11 | $ 4 |
Collateral already posted, aggregate fair value | 193 | 62 |
Energy-related derivatives | ||
Liabilities: | ||
Collateral already posted, aggregate fair value | 6 | 8 |
Recurring | ||
Assets: | ||
Interest rate derivatives | 1 | 14 |
Foreign Currency Derivative Instruments Not Designated as Hedging Instruments, Asset at Fair Value | 129 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 1,455 | 1,172 |
Other investments | 10 | 10 |
Total | 3,995 | 3,471 |
Liabilities: | ||
Interest rate derivatives | 38 | 29 |
Contingent consideration | 22 | 18 |
Total | 816 | 735 |
Recurring | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 772 | 662 |
Recurring | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 286 | 216 |
Recurring | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 251 | 92 |
Recurring | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 68 | 73 |
Recurring | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 336 | 332 |
Recurring | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 57 | 183 |
Recurring | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 29 | 20 |
Recurring | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 31 | 26 |
Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 570 | 671 |
Liabilities: | ||
Energy-related derivatives | 733 | 630 |
Recurring | Foreign currency derivatives | ||
Liabilities: | ||
Foreign currency derivatives | 23 | 58 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets: | ||
Interest rate derivatives | 0 | 0 |
Foreign Currency Derivative Instruments Not Designated as Hedging Instruments, Asset at Fair Value | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 1,455 | 1,172 |
Other investments | 9 | 9 |
Total | 2,587 | 2,189 |
Liabilities: | ||
Interest rate derivatives | 0 | 0 |
Contingent consideration | 0 | 0 |
Total | 480 | 345 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 690 | 589 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 62 | 48 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 21 | 22 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 19 | 11 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 331 | 338 |
Liabilities: | ||
Energy-related derivatives | 480 | 345 |
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency derivatives | ||
Liabilities: | ||
Foreign currency derivatives | 0 | 0 |
Recurring | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Interest rate derivatives | 1 | 14 |
Foreign Currency Derivative Instruments Not Designated as Hedging Instruments, Asset at Fair Value | 129 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Other investments | 0 | 0 |
Total | 1,378 | 1,261 |
Liabilities: | ||
Interest rate derivatives | 38 | 29 |
Contingent consideration | 0 | 0 |
Total | 314 | 372 |
Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 82 | 73 |
Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 224 | 168 |
Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 251 | 92 |
Recurring | Significant Other Observable Inputs (Level 2) | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 68 | 73 |
Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 315 | 310 |
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 57 | 183 |
Recurring | Significant Other Observable Inputs (Level 2) | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Other Observable Inputs (Level 2) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 12 | 15 |
Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 239 | 333 |
Liabilities: | ||
Energy-related derivatives | 253 | 285 |
Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency derivatives | ||
Liabilities: | ||
Foreign currency derivatives | 23 | 58 |
Recurring | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Interest rate derivatives | 0 | 0 |
Foreign Currency Derivative Instruments Not Designated as Hedging Instruments, Asset at Fair Value | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Other investments | 1 | 1 |
Total | 1 | 1 |
Liabilities: | ||
Interest rate derivatives | 0 | 0 |
Contingent consideration | 22 | 18 |
Total | 22 | 18 |
Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency derivatives | ||
Liabilities: | ||
Foreign currency derivatives | 0 | 0 |
ALABAMA POWER CO | ||
Assets: | ||
Derivatives | 4 | 20 |
Liabilities: | ||
Energy-related derivatives | 10 | 9 |
ALABAMA POWER CO | Recurring | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts, NAV | 29 | 20 |
Cash equivalents | 349 | 262 |
Total | 1,255 | 1,072 |
ALABAMA POWER CO | Recurring | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 523 | 457 |
ALABAMA POWER CO | Recurring | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 121 | 95 |
ALABAMA POWER CO | Recurring | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 24 | 21 |
ALABAMA POWER CO | Recurring | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 181 | 168 |
ALABAMA POWER CO | Recurring | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 18 | 19 |
ALABAMA POWER CO | Recurring | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 29 | 20 |
Nuclear decommissioning trusts, NAV | 29 | 20 |
ALABAMA POWER CO | Recurring | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 6 | 10 |
ALABAMA POWER CO | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 4 | 20 |
Liabilities: | ||
Energy-related derivatives | 10 | 9 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 349 | 262 |
Total | 880 | 717 |
Liabilities: | ||
Interest rate derivatives | 0 | |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 442 | 385 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 62 | 48 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 21 | 22 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 6 | 0 |
ALABAMA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 346 | 335 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 81 | 72 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 59 | 47 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 24 | 21 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 160 | 146 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 18 | 19 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 10 |
ALABAMA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 4 | 20 |
Liabilities: | ||
Energy-related derivatives | 10 | 9 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 0 | 0 |
Liabilities: | ||
Interest rate derivatives | 0 | |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
ALABAMA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | |
GEORGIA POWER CO | ||
Assets: | ||
Derivatives | 6 | 46 |
Liabilities: | ||
Energy-related derivatives | (24) | 11 |
GEORGIA POWER CO | Recurring | ||
Assets: | ||
Interest rate derivatives | 2 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 690 | 860 |
Total | 1,625 | |
Liabilities: | ||
Energy-related derivatives | 24 | 11 |
GEORGIA POWER CO | Recurring | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 249 | 205 |
GEORGIA POWER CO | Recurring | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 166 | 121 |
GEORGIA POWER CO | Recurring | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 227 | 71 |
GEORGIA POWER CO | Recurring | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 68 | 73 |
GEORGIA POWER CO | Recurring | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 155 | 164 |
GEORGIA POWER CO | Recurring | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 40 | 164 |
GEORGIA POWER CO | Recurring | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 24 | 16 |
GEORGIA POWER CO | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 6 | 44 |
Liabilities: | ||
Energy-related derivatives | 19 | 8 |
GEORGIA POWER CO | Recurring | Interest rate derivatives | ||
Liabilities: | ||
Energy-related derivatives | 5 | 3 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets: | ||
Interest rate derivatives | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 690 | 215 |
Total | 950 | |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 248 | 204 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 12 | 11 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GEORGIA POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivatives | ||
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Interest rate derivatives | 2 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 645 |
Total | 675 | |
Liabilities: | ||
Energy-related derivatives | 24 | 11 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 1 | 1 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 166 | 121 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 227 | 71 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 68 | 73 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 155 | 164 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 40 | 164 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 12 | 5 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 6 | 44 |
Liabilities: | ||
Energy-related derivatives | 19 | 8 |
GEORGIA POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Interest rate derivatives | ||
Liabilities: | ||
Energy-related derivatives | 5 | 3 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Interest rate derivatives | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 0 | |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Municipal bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Mortgage- and asset-backed securities | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Other | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GEORGIA POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Interest rate derivatives | ||
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GULF POWER CO | ||
Assets: | ||
Derivatives | 0 | 5 |
Liabilities: | ||
Energy-related derivatives | 21 | 29 |
GULF POWER CO | Recurring | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 21 | 20 |
Total | 25 | |
GULF POWER CO | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 5 | |
Liabilities: | ||
Energy-related derivatives | 21 | 29 |
GULF POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 21 | 20 |
Total | 20 | |
GULF POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
GULF POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 5 | |
GULF POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 5 | |
Liabilities: | ||
Energy-related derivatives | 21 | 29 |
GULF POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 0 | |
GULF POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
MISSISSIPPI POWER CO | ||
Assets: | ||
Derivatives | 3 | 7 |
Liabilities: | ||
Energy-related derivatives | 9 | 11 |
MISSISSIPPI POWER CO | Recurring | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 224 | 206 |
Total | 227 | 212 |
MISSISSIPPI POWER CO | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 2 | 3 |
Liabilities: | ||
Energy-related derivatives | 9 | 10 |
MISSISSIPPI POWER CO | Recurring | Interest rate derivatives | ||
Assets: | ||
Interest rate derivatives | 1 | 3 |
MISSISSIPPI POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 224 | 206 |
Total | 224 | 206 |
MISSISSIPPI POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
MISSISSIPPI POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivatives | ||
Assets: | ||
Interest rate derivatives | 0 | 0 |
MISSISSIPPI POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 3 | 6 |
MISSISSIPPI POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 2 | 3 |
Liabilities: | ||
Energy-related derivatives | 9 | 10 |
MISSISSIPPI POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Interest rate derivatives | ||
Assets: | ||
Interest rate derivatives | 1 | 3 |
MISSISSIPPI POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 0 | 0 |
MISSISSIPPI POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
MISSISSIPPI POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Interest rate derivatives | ||
Assets: | ||
Interest rate derivatives | 0 | 0 |
SOUTHERN POWER CO | Recurring | ||
Assets: | ||
Interest rate derivatives | 1 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 21 | 628 |
Total | 153 | 650 |
Liabilities: | ||
Contingent consideration | 22 | 18 |
Total | 58 | 81 |
SOUTHERN POWER CO | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 3 | 21 |
Liabilities: | ||
Energy-related derivatives | 13 | 5 |
SOUTHERN POWER CO | Recurring | Foreign currency derivatives | ||
Assets: | ||
Derivatives | 129 | |
Liabilities: | ||
Foreign currency derivatives | 23 | 58 |
SOUTHERN POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Assets: | ||
Interest rate derivatives | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 21 | 628 |
Total | 21 | 628 |
Liabilities: | ||
Contingent consideration | 0 | 0 |
Total | 0 | 0 |
SOUTHERN POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
SOUTHERN POWER CO | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency derivatives | ||
Assets: | ||
Derivatives | 0 | |
Liabilities: | ||
Foreign currency derivatives | 0 | 0 |
SOUTHERN POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Interest rate derivatives | 1 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 132 | 22 |
Liabilities: | ||
Contingent consideration | 0 | 0 |
Total | 36 | 63 |
SOUTHERN POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 3 | 21 |
Liabilities: | ||
Energy-related derivatives | 13 | 5 |
SOUTHERN POWER CO | Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency derivatives | ||
Assets: | ||
Derivatives | 129 | |
Liabilities: | ||
Foreign currency derivatives | 23 | 58 |
SOUTHERN POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Interest rate derivatives | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Total | 0 | 0 |
Liabilities: | ||
Contingent consideration | 22 | 18 |
Total | 22 | 18 |
SOUTHERN POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | 0 |
Liabilities: | ||
Energy-related derivatives | 0 | 0 |
SOUTHERN POWER CO | Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency derivatives | ||
Assets: | ||
Derivatives | 0 | |
Liabilities: | ||
Foreign currency derivatives | 0 | 0 |
SOUTHERN Co GAS | ||
Assets: | ||
Derivatives | 554 | |
Liabilities: | ||
Energy-related derivatives | 581 | |
Weather derivative premium | 11 | 4 |
Collateral already posted, aggregate fair value | 193 | 62 |
SOUTHERN Co GAS | Energy-related derivatives | ||
Liabilities: | ||
Collateral already posted, aggregate fair value | 6 | |
SOUTHERN Co GAS | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 554 | |
Liabilities: | ||
Energy-related derivatives | 660 | |
SOUTHERN Co GAS | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 331 | |
Liabilities: | ||
Energy-related derivatives | 479 | |
SOUTHERN Co GAS | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 223 | |
Liabilities: | ||
Energy-related derivatives | 181 | |
SOUTHERN Co GAS | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | |
Liabilities: | ||
Energy-related derivatives | 0 | |
Predecessor | SOUTHERN Co GAS | ||
Assets: | ||
Derivatives | 660 | |
Liabilities: | ||
Energy-related derivatives | 569 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | ||
Liabilities: | ||
Collateral already posted, aggregate fair value | 8 | |
Predecessor | SOUTHERN Co GAS | Recurring | Energy-related derivatives | ||
Assets: | ||
Derivatives | 577 | |
Liabilities: | ||
Energy-related derivatives | 569 | |
Predecessor | SOUTHERN Co GAS | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 338 | |
Liabilities: | ||
Energy-related derivatives | 345 | |
Predecessor | SOUTHERN Co GAS | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 239 | |
Liabilities: | ||
Energy-related derivatives | 224 | |
Predecessor | SOUTHERN Co GAS | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | ||
Assets: | ||
Derivatives | 0 | |
Liabilities: | ||
Energy-related derivatives | 0 | |
Nuclear Decommissioning Trusts | Recurring | ||
Nuclear decommissioning trusts: | ||
Total | 29 | 20 |
Nuclear Decommissioning Trusts | Recurring | Private equity | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts, NAV | $ 29 | $ 20 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value, Nature and Risk of Investments (Details) - Private equity - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Fair value | $ 29 | $ 20 |
Unfunded commitments | 21 | 25 |
ALABAMA POWER CO | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Fair value | 29 | 20 |
Unfunded commitments | $ 21 | $ 25 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments, Carrying Amount Not Equal to Fair Value (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | $ 48,151 | $ 45,080 |
Fair Value | 51,348 | 46,286 |
ALABAMA POWER CO | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 7,625 | 7,092 |
Fair Value | 8,305 | 7,544 |
GEORGIA POWER CO | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 11,777 | 10,516 |
Fair Value | 12,531 | 11,034 |
GULF POWER CO | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 1,285 | 1,074 |
Fair Value | 1,334 | 1,097 |
MISSISSIPPI POWER CO | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 2,086 | 2,979 |
Fair Value | 2,076 | 2,922 |
SOUTHERN POWER CO | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 5,841 | 5,628 |
Fair Value | 6,079 | 5,691 |
SOUTHERN Co GAS | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 6,048 | |
Fair Value | $ 6,471 | |
Predecessor | SOUTHERN Co GAS | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 5,281 | |
Fair Value | $ 5,491 |
Fair Value Measurements - Textu
Fair Value Measurements - Textual (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Private equity | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Entities that calculation NAV, liquidation investment, remaining period | 10 years |
Derivatives - Textual (Details)
Derivatives - Textual (Details) | Jan. 23, 2015USD ($) | Sep. 30, 2016USD ($) | May 31, 2016USD ($) | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)MMBTU | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Nov. 30, 2015USD ($) |
Derivative [Line Items] | |||||||||
Notional amount | $ 3,650,000,000 | ||||||||
Derivative collateral obligation to return cash | $ 0 | ||||||||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 32,000,000 | ||||||||
Realized gain (loss) on termination of interest rate derivatives | $ 91,000,000 | $ (220,000,000) | $ (22,000,000) | ||||||
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period | (20,000,000) | ||||||||
Cash flow hedge gain (loss) to be reclassified within twelve months | (11,000,000) | ||||||||
ALABAMA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Derivative collateral obligation to return cash | $ 0 | ||||||||
Longest hedge date | 2,020 | ||||||||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 5,000,000 | ||||||||
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period | $ (6,000,000) | ||||||||
Fair value of derivative liabilities with contingent features | 1,000,000 | ||||||||
Cash flow hedge ineffectiveness recorded in earnings | 0 | ||||||||
Derivative liability, fair value of collateral | $ 12,000,000 | ||||||||
GEORGIA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Required period for options and hedges | 48 months | ||||||||
Notional amount | $ 950,000,000 | ||||||||
Derivative collateral obligation to return cash | $ 0 | ||||||||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 10,000,000 | ||||||||
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period | $ (4,000,000) | ||||||||
Fair value of derivative liabilities with contingent features | 2,000,000 | ||||||||
Derivative liability, fair value of collateral | 12,000,000 | ||||||||
GULF POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Derivative collateral obligation to return cash | $ 0 | ||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 22,000,000 | ||||||||
Longest hedge date | 2,020 | ||||||||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 3,000,000 | ||||||||
Derivative liability, fair value of collateral | $ 12,000,000 | ||||||||
MISSISSIPPI POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Increase (Decrease) Cash Collateral from Counterparties | $ 0 | ||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 53,000,000 | ||||||||
Longest hedge date | 2,021 | ||||||||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 4,000,000 | ||||||||
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period | $ (500,000) | ||||||||
Fair value of derivative liabilities with contingent features | 1,000,000 | ||||||||
Derivative liability, fair value of collateral | 12,000,000 | ||||||||
SOUTHERN POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Derivative collateral obligation to return cash | $ 0 | $ 0 | 0 | ||||||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 10,000,000 | ||||||||
Realized gain (loss) on termination of interest rate derivatives | $ 102,000,000 | (44,000,000) | 0 | ||||||
Fair value of derivative liabilities with contingent features | 8,000,000 | ||||||||
Cash flow hedge gain (loss) to be reclassified within twelve months | (7,000,000) | ||||||||
Interest rate derivatives outstanding | 0 | ||||||||
Deferred gain (loss) on interest rate cash flow hedges, accumulated other comprehensive income | 0 | ||||||||
Cash flow hedge ineffectiveness recorded in earnings | 0 | ||||||||
Derivative liability, fair value of collateral | 12,000,000 | ||||||||
SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Increase (Decrease) Cash Collateral from Counterparties | 0 | ||||||||
Derivative collateral obligation to return cash | 0 | ||||||||
Realized gain (loss) on termination of interest rate derivatives | (3,000,000) | ||||||||
Fair value of derivative liabilities with contingent features | 3,000,000 | ||||||||
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 2,000,000 | ||||||||
Cash flow hedge gain (loss) to be reclassified within twelve months | 4,000,000 | ||||||||
Parent Company and Southern Power | |||||||||
Derivative [Line Items] | |||||||||
Foreign currency cash flow hedge gain (loss) to be reclassified during next 12 months | (23,000,000) | ||||||||
Interest rate derivatives | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | (2,000,000) | (180,000,000) | (22,000,000) | ||||||
Fair value of derivative liabilities with contingent features | 7,000,000 | ||||||||
Interest rate derivatives | ALABAMA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Notional amount | 0 | ||||||||
Realized gain (loss) on termination of interest rate derivatives | 0 | (3,000,000) | (7,000,000) | ||||||
Interest rate derivatives | GEORGIA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | 1,000,000 | 0 | (15,000,000) | ||||||
Interest rate derivatives | GULF POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Notional amount | 0 | ||||||||
Interest rate derivatives | SOUTHERN POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | $ 0 | 0 | 0 | ||||||
Interest rate derivatives | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | (5,000,000) | ||||||||
Interest Rate Swap | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Notional amount | $ 800,000,000 | ||||||||
Public Utilities, Inventory, Natural Gas | |||||||||
Derivative [Line Items] | |||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 621,000,000 | ||||||||
Public Utilities, Inventory, Natural Gas | ALABAMA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 69,000,000 | ||||||||
Public Utilities, Inventory, Natural Gas | GEORGIA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 163,000,000 | ||||||||
Longest hedge date | 2,021 | ||||||||
Public Utilities, Inventory, Natural Gas | SOUTHERN POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 14,000,000 | ||||||||
Longest non-hedge date | 2,018 | ||||||||
Public Utilities, Inventory, Natural Gas | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 300,000,000 | ||||||||
Public Utilities, Inventory, Power Position | SOUTHERN POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 3,000,000 | ||||||||
Public Utilities, Inventory, Fuel | |||||||||
Derivative [Line Items] | |||||||||
Longest hedge date | 2,021 | ||||||||
Longest non-hedge date | 2,026 | ||||||||
Public Utilities, Inventory, Fuel | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Longest hedge date | 2,020 | ||||||||
Longest non-hedge date | 2,026 | ||||||||
Energy-related derivatives | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | $ (47,000,000) | 18,000,000 | 0 | ||||||
Fair value of derivative liabilities with contingent features | 15,000,000 | ||||||||
Derivative liability, fair value of collateral | 14,000,000 | ||||||||
Energy-related derivatives | SOUTHERN POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | (38,000,000) | 14,000,000 | 0 | ||||||
Energy-related derivatives | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | $ 2,000,000 | (9,000,000) | |||||||
Minimum | Interest Rate Swap | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Term of contract | 10 years | ||||||||
Maximum | Interest Rate Swap | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Term of contract | 30 years | ||||||||
Cash Flow Hedging | MISSISSIPPI POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | 0 | $ 0 | $ 0 | ||||||
Cash Flow Hedging | Interest rate derivatives | GEORGIA POWER CO | |||||||||
Derivative [Line Items] | |||||||||
Notional amount | $ 0 | ||||||||
Cash Flow Hedging | Interest rate derivatives | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Realized gain (loss) on termination of interest rate derivatives | $ (5,000,000) | ||||||||
Cash Flow Hedging | Interest Rate Swap | SOUTHERN Co GAS | |||||||||
Derivative [Line Items] | |||||||||
Derivative, settlement, notional amount | $ 200,000,000 | $ 400,000,000 | $ 200,000,000 | $ 200,000,000 | |||||
Derivative instruments, loss recognized in other comprehensive income (loss), effective portion | $ 35,000,000 | $ 26,000,000 |
Derivatives - Interest Rate Der
Derivatives - Interest Rate Derivatives (Details) | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Derivative [Line Items] | |
Notional amount | $ 3,650,000,000 |
Fair value gain (loss) | (36,000,000) |
Maturity Date March 2018 | Cash Flow Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 900,000,000 |
Notional amount of interest rate derivatives, interest rate paid | 0.79% |
Interest rate received | 1-month LIBOR |
Hedge maturity date | Mar. 1, 2018 |
Fair value gain (loss) | $ 1,000,000 |
Maturity Date August 2017 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Interest rate received | |
Basis spread on variable rate | 0.17% |
Maturity Date June 2018 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 250,000,000 |
Notional amount of interest rate derivatives, interest rate received | 5.40% |
Interest rate received | 3-month LIBOR + 4.02% |
Basis spread on variable rate | 4.02% |
Hedge maturity date | Jun. 1, 2018 |
Fair value gain (loss) | $ 0 |
Maturity Date December 2018 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 500,000,000 |
Notional amount of interest rate derivatives, interest rate received | 1.95% |
Interest rate received | 3-month LIBOR + 0.76% |
Basis spread on variable rate | 0.76% |
Hedge maturity date | Dec. 1, 2018 |
Fair value gain (loss) | $ (3,000,000) |
Maturity Date December 2019 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 200,000,000 |
Notional amount of interest rate derivatives, interest rate received | 4.25% |
Interest rate received | 3-month LIBOR + 2.46% |
Basis spread on variable rate | 2.46% |
Hedge maturity date | Dec. 1, 2019 |
Fair value gain (loss) | $ (1,000,000) |
Maturity Date June 2020 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 300,000,000 |
Notional amount of interest rate derivatives, interest rate received | 2.75% |
Interest rate received | 3-month LIBOR + 0.92% |
Basis spread on variable rate | 0.92% |
Hedge maturity date | Jun. 15, 2020 |
Fair value gain (loss) | $ (2,000,000) |
Maturity Date June 2021 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 1,500,000,000 |
Notional amount of interest rate derivatives, interest rate received | 2.35% |
Interest rate received | 1-month LIBOR + 0.87% |
Basis spread on variable rate | 0.87% |
Hedge maturity date | Jul. 1, 2021 |
Fair value gain (loss) | $ (31,000,000) |
GEORGIA POWER CO | |
Derivative [Line Items] | |
Notional amount | 950,000,000 |
Fair value gain (loss) | (4,000,000) |
GEORGIA POWER CO | Maturity Date June 2018 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 250,000,000 |
Notional amount of interest rate derivatives, interest rate paid | 5.40% |
Interest rate received | 3-month LIBOR + 4.02% |
Basis spread on variable rate | 4.02% |
Hedge maturity date | Jun. 1, 2018 |
Fair value gain (loss) | $ 0 |
GEORGIA POWER CO | Maturity Date December 2018 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 500,000,000 |
Notional amount of interest rate derivatives, interest rate paid | 1.95% |
Interest rate received | 3-month LIBOR + 0.76% |
Basis spread on variable rate | 0.76% |
Hedge maturity date | Dec. 1, 2018 |
Fair value gain (loss) | $ (3,000,000) |
GEORGIA POWER CO | Maturity Date December 2019 | Fair Value Hedges of Existing Debt | |
Derivative [Line Items] | |
Notional amount | $ 200,000,000 |
Notional amount of interest rate derivatives, interest rate paid | 4.25% |
Interest rate received | 3-month LIBOR + 2.46% |
Basis spread on variable rate | 2.46% |
Hedge maturity date | Dec. 1, 2019 |
Fair value gain (loss) | $ (1,000,000) |
GULF POWER CO | Interest rate derivatives | |
Derivative [Line Items] | |
Notional amount | 0 |
MISSISSIPPI POWER CO | Maturity Date March 2018 | Cash Flow Hedges of Existing Debt | Interest rate derivatives | |
Derivative [Line Items] | |
Notional amount | $ 900,000,000 |
Notional amount of interest rate derivatives, interest rate paid | 0.79% |
Fair value gain (loss) | $ 1,000,000 |
Derivatives - Foreign Currency
Derivatives - Foreign Currency Derivatives (Details) - 12 months ended Dec. 31, 2017 € in Millions, $ in Millions | USD ($) | EUR (€) |
Derivative [Line Items] | ||
Fair value gain (loss) | $ (36) | |
Foreign currency derivatives | Cash Flow Hedges of Existing Debt | ||
Derivative [Line Items] | ||
Pay Notional | 1,241 | |
Receive Notional | € | € 1,100 | |
Fair value gain (loss) | 106 | |
SOUTHERN POWER CO | Foreign currency derivatives | Maturity Date June 2022 | Cash Flow Hedges of Existing Debt | ||
Derivative [Line Items] | ||
Pay Notional | $ 677 | |
Pay Rate | 2.95% | |
Receive Notional | € | 600 | |
Receive Rate | 1.00% | |
Fair value gain (loss) | $ 55 | |
SOUTHERN POWER CO | Foreign currency derivatives | Maturity Date June 2026 | Cash Flow Hedges of Existing Debt | ||
Derivative [Line Items] | ||
Pay Notional | $ 564 | |
Pay Rate | 3.78% | |
Receive Notional | € | € 500 | |
Receive Rate | 1.85% | |
Fair value gain (loss) | $ 51 |
Derivatives - Financial Stateme
Derivatives - Financial Statement Presentation (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Collateral already posted, aggregate fair value | $ 193 | $ 62 |
Weather derivative premium | 11 | 4 |
Energy-related derivatives | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Collateral already posted, aggregate fair value | 6 | 8 |
Parent Company | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 700 | 690 |
Derivative asset, gross amount offset | (405) | (462) |
Derivative Asset | 295 | 228 |
Derivative liability, gross | 794 | 718 |
Derivative liability, gross amounts offset | (598) | (524) |
Derivative Liability | 196 | 194 |
Parent Company | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 550 | 556 |
Derivative liability, gross | 652 | 564 |
Parent Company | Energy-related derivatives | Other current assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 380 | 489 |
Parent Company | Energy-related derivatives | Liabilities from risk management activities, net of collateral | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 437 | 483 |
Parent Company | Energy-related derivatives | Other deferred charges and assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 170 | 66 |
Parent Company | Energy-related derivatives | Other deferred credits and liabilities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 215 | 81 |
Parent Company | Interest rate derivatives | Other current assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 1 |
ALABAMA POWER CO | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 4 | 20 |
Derivative asset, gross amount offset | (4) | (8) |
Derivative Asset | 0 | 12 |
Derivative liability, gross | 10 | 9 |
Derivative liability, gross amounts offset | (4) | (8) |
Derivative Liability | 6 | 1 |
GEORGIA POWER CO | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 6 | 46 |
Derivative asset, gross amount offset | (6) | (8) |
Derivative Asset | 0 | 38 |
Derivative liability, gross | (24) | 11 |
Derivative liability, gross amounts offset | 6 | (8) |
Derivative Liability | (18) | 3 |
GULF POWER CO | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 5 |
Derivative asset, gross amount offset | 0 | (4) |
Derivative Asset | 0 | 1 |
Derivative liability, gross | 21 | 29 |
Derivative liability, gross amounts offset | 0 | (4) |
Derivative Liability | 21 | 25 |
MISSISSIPPI POWER CO | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 3 | 7 |
Derivative asset, gross amount offset | (2) | (3) |
Derivative Asset | 1 | 4 |
Derivative liability, gross | 9 | 11 |
Derivative liability, gross amounts offset | (2) | (3) |
Derivative Liability | 7 | 8 |
SOUTHERN POWER CO | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 4 |
Derivative liability, gross | 2 | 1 |
SOUTHERN POWER CO | Energy-related derivatives | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 132 | 22 |
Derivative asset, gross amount offset | (3) | (5) |
Derivative Asset | 129 | 17 |
Derivative liability, gross | 36 | 63 |
Derivative liability, gross amounts offset | (3) | (5) |
Derivative Liability | 33 | 58 |
SOUTHERN POWER CO | Energy-related derivatives | Other deferred charges and assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 3 |
SOUTHERN POWER CO | Energy-related derivatives | Other deferred credits and liabilities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 2 | 1 |
SOUTHERN POWER CO | Interest rate derivatives | Other current assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 1 |
SOUTHERN POWER CO | Interest rate derivatives | Other current liabilities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | 0 |
SOUTHERN Co GAS | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 554 | |
Derivative asset, gross amount offset | (390) | |
Derivative Asset | 164 | |
Derivative liability, gross | 581 | |
Derivative liability, gross amounts offset | (435) | |
Derivative Liability | 146 | |
Collateral already posted, aggregate fair value | 193 | 62 |
Weather derivative premium | 11 | 4 |
SOUTHERN Co GAS | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 549 | |
Derivative liability, gross | 552 | |
SOUTHERN Co GAS | Energy-related derivatives | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Collateral already posted, aggregate fair value | 6 | |
SOUTHERN Co GAS | Energy-related derivatives | Liabilities from risk management activities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 486 | |
SOUTHERN Co GAS | Energy-related derivatives | Other deferred charges and assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 170 | |
SOUTHERN Co GAS | Energy-related derivatives | Assets From Risk Management Activities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 379 | |
SOUTHERN Co GAS | Energy-related derivatives | Other deferred credits and liabilities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 66 | |
Hedging Instruments for Regulatory Purposes | Parent Company | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 17 | 98 |
Derivative liability, gross | 67 | 60 |
Hedging Instruments for Regulatory Purposes | Parent Company | Energy-related derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 10 | 73 |
Hedging Instruments for Regulatory Purposes | Parent Company | Energy-related derivatives | Liabilities from risk management activities, net of collateral | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 43 | 27 |
Hedging Instruments for Regulatory Purposes | Parent Company | Energy-related derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 7 | 25 |
Hedging Instruments for Regulatory Purposes | Parent Company | Energy-related derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 24 | 33 |
Hedging Instruments for Regulatory Purposes | Parent Company | Interest rate derivatives | Liabilities from risk management activities | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | 0 |
Hedging Instruments for Regulatory Purposes | ALABAMA POWER CO | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 4 | 20 |
Derivative liability, gross | 10 | 9 |
Hedging Instruments for Regulatory Purposes | ALABAMA POWER CO | Energy-related derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 2 | 13 |
Hedging Instruments for Regulatory Purposes | ALABAMA POWER CO | Energy-related derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 2 | 7 |
Hedging Instruments for Regulatory Purposes | ALABAMA POWER CO | Energy-related derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 6 | 5 |
Hedging Instruments for Regulatory Purposes | ALABAMA POWER CO | Energy-related derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 4 | 4 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 6 | 44 |
Derivative liability, gross | (19) | 8 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 2 | 30 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 4 | 14 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | (9) | 1 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | (10) | 7 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 5 |
Derivative liability, gross | 21 | 29 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other current assets | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 4 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Liabilities from risk management activities | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 14 | 12 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other deferred charges and assets | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 1 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other deferred credits and liabilities | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 7 | 17 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 2 | 4 |
Derivative liability, gross | 9 | 11 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 1 | 2 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 1 | 2 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 6 | 6 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 3 | 5 |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 5 | |
Derivative liability, gross | 25 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Liabilities from risk management activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 24 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Assets From Risk Management Activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 5 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 1 | |
Cash Flow and Fair Value Hedging | Parent Company | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 133 | 36 |
Derivative liability, gross | 75 | 94 |
Cash Flow and Fair Value Hedging | Parent Company | Energy-related derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 3 | 23 |
Cash Flow and Fair Value Hedging | Parent Company | Energy-related derivatives | Liabilities from risk management activities, net of collateral | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 14 | 7 |
Cash Flow and Fair Value Hedging | Parent Company | Foreign currency derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 0 |
Cash Flow and Fair Value Hedging | Parent Company | Foreign currency derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 129 | 0 |
Cash Flow and Fair Value Hedging | Parent Company | Foreign currency derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 23 | 25 |
Cash Flow and Fair Value Hedging | Parent Company | Foreign currency derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | 33 |
Cash Flow and Fair Value Hedging | Parent Company | Interest rate derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 1 | 12 |
Cash Flow and Fair Value Hedging | Parent Company | Interest rate derivatives | Liabilities from risk management activities, net of collateral | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 4 | 1 |
Cash Flow and Fair Value Hedging | Parent Company | Interest rate derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 1 |
Cash Flow and Fair Value Hedging | Parent Company | Interest rate derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 34 | 28 |
Cash Flow and Fair Value Hedging | GEORGIA POWER CO | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 2 |
Derivative liability, gross | (5) | 3 |
Cash Flow and Fair Value Hedging | GEORGIA POWER CO | Interest rate derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 2 |
Cash Flow and Fair Value Hedging | GEORGIA POWER CO | Interest rate derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 0 |
Cash Flow and Fair Value Hedging | GEORGIA POWER CO | Interest rate derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | (4) | 0 |
Cash Flow and Fair Value Hedging | GEORGIA POWER CO | Interest rate derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | (1) | 3 |
Cash Flow and Fair Value Hedging | MISSISSIPPI POWER CO | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 1 | 3 |
Derivative liability, gross | 0 | 0 |
Cash Flow and Fair Value Hedging | MISSISSIPPI POWER CO | Interest rate derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 1 | 2 |
Cash Flow and Fair Value Hedging | MISSISSIPPI POWER CO | Interest rate derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 1 |
Cash Flow and Fair Value Hedging | MISSISSIPPI POWER CO | Interest rate derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | 0 |
Cash Flow and Fair Value Hedging | MISSISSIPPI POWER CO | Interest rate derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | 0 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 132 | 18 |
Derivative liability, gross | 34 | 62 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Energy-related derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 3 | 18 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Energy-related derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 11 | 4 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Foreign currency derivatives | Other current assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | 0 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Foreign currency derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 129 | 0 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Foreign currency derivatives | Other current liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 23 | 25 |
Cash Flow and Fair Value Hedging | SOUTHERN POWER CO | Foreign currency derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | 33 |
Cash Flow and Fair Value Hedging | SOUTHERN Co GAS | Energy-related derivatives | Liabilities from risk management activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 4 | |
Cash Flow and Fair Value Hedging | SOUTHERN Co GAS | Energy-related derivatives | Assets From Risk Management Activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | $ 0 | |
Predecessor | SOUTHERN Co GAS | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 660 | |
Derivative asset, gross amount offset | (583) | |
Derivative Asset | 77 | |
Derivative liability, gross | 569 | |
Derivative liability, gross amounts offset | (497) | |
Derivative Liability | 72 | |
Predecessor | SOUTHERN Co GAS | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 649 | |
Derivative liability, gross | 563 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Collateral already posted, aggregate fair value | 8 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Liabilities from risk management activities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 482 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Other deferred charges and assets | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 215 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Assets From Risk Management Activities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 434 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Other deferred credits and liabilities | Not Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 81 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 8 | |
Derivative liability, gross | 3 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Liabilities from risk management activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 3 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other deferred charges and assets | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 0 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Assets From Risk Management Activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | 8 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other deferred credits and liabilities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 0 | |
Predecessor | Cash Flow and Fair Value Hedging | SOUTHERN Co GAS | Energy-related derivatives | Liabilities from risk management activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative liability, gross | 3 | |
Predecessor | Cash Flow and Fair Value Hedging | SOUTHERN Co GAS | Energy-related derivatives | Assets From Risk Management Activities | Designated as Hedging Instrument | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative asset, gross | $ 3 |
Derivatives - Pre-Tax Effects o
Derivatives - Pre-Tax Effects of Unrealized Derivative Gains (Losses) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | $ (52) | $ (35) |
Regulatory hedge unrealized gain | 8 | 68 |
Collateral already posted, aggregate fair value | 193 | 62 |
Energy-related derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Collateral already posted, aggregate fair value | 6 | 8 |
Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (34) | (16) |
Energy-related derivatives | Other regulatory liabilities current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 7 | 56 |
Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (18) | (19) |
Energy-related derivatives | Other regulatory liabilities deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 1 | 12 |
ALABAMA POWER CO | Other regulatory assets | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (7) | (1) |
ALABAMA POWER CO | Other regulatory liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 1 | 12 |
ALABAMA POWER CO | Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (4) | (1) |
ALABAMA POWER CO | Energy-related derivatives | Other current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 1 | 8 |
ALABAMA POWER CO | Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (3) | 0 |
ALABAMA POWER CO | Energy-related derivatives | Other regulatory liabilities deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 4 |
SOUTHERN Co GAS | ||
Derivatives, Fair Value [Line Items] | ||
Collateral already posted, aggregate fair value | 193 | 62 |
SOUTHERN Co GAS | Energy-related derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Collateral already posted, aggregate fair value | 6 | |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (7) | 0 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other regulatory liabilities current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 29 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (6) | 0 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other deferred credits and liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 7 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (13) | 0 |
Hedging Instruments for Regulatory Purposes | GEORGIA POWER CO | Energy-related derivatives | Other regulatory liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 36 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (21) | (25) |
Regulatory hedge unrealized gain | 0 | 1 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (14) | (9) |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other regulatory liabilities current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 1 |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (7) | (16) |
Hedging Instruments for Regulatory Purposes | GULF POWER CO | Energy-related derivatives | Other regulatory liabilities deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 0 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (7) | (8) |
Regulatory hedge unrealized gain | 0 | 1 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (5) | (5) |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory liabilities current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 1 |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (2) | (3) |
Hedging Instruments for Regulatory Purposes | MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory liabilities deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | 0 |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (4) | |
Regulatory hedge unrealized gain | 7 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (4) | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 7 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | 0 | |
Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 0 | |
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Collateral already posted, aggregate fair value | $ 8 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (1) | |
Regulatory hedge unrealized gain | 18 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | (1) | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities current | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | 17 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized loss | 0 | |
Predecessor | Hedging Instruments for Regulatory Purposes | SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities deferred | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory hedge unrealized gain | $ 1 |
Derivatives - Pre-Tax Effect129
Derivatives - Pre-Tax Effects of Derivatives Designated as Cash Flow Hedging (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | $ 91 | $ (220) | $ (22) | ||
Gain (loss) reclassified from AOCI into income (effective portion) | 98 | (112) | (9) | ||
Energy-related derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | (47) | 18 | 0 | ||
Energy-related derivatives | Depreciation and Amortization | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (16) | 2 | 0 | ||
Energy-related derivatives | Cost of Natural Gas | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (2) | (1) | 0 | ||
Interest rate derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | (2) | (180) | (22) | ||
Interest rate derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (21) | (18) | (9) | ||
Foreign currency derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 140 | (58) | 0 | ||
Foreign currency derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (23) | (13) | 0 | ||
Foreign currency derivatives | Other Nonoperating Income (Expense) | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | 160 | (82) | 0 | ||
ALABAMA POWER CO | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (6) | (6) | (3) | ||
ALABAMA POWER CO | Interest rate derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 0 | (3) | (7) | ||
GEORGIA POWER CO | Interest rate derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 1 | 0 | (15) | ||
GEORGIA POWER CO | Interest rate derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (4) | (4) | (3) | ||
SOUTHERN POWER CO | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 102 | (44) | 0 | ||
Gain (loss) reclassified from AOCI into income (effective portion) | 119 | (94) | (1) | ||
SOUTHERN POWER CO | Energy-related derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | (38) | 14 | 0 | ||
SOUTHERN POWER CO | Energy-related derivatives | Amortization | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (17) | 2 | 0 | ||
SOUTHERN POWER CO | Interest rate derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 0 | 0 | 0 | ||
SOUTHERN POWER CO | Interest rate derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | 0 | (1) | (1) | ||
SOUTHERN POWER CO | Foreign currency derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 140 | (58) | 0 | ||
SOUTHERN POWER CO | Foreign currency derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (23) | (13) | 0 | ||
SOUTHERN POWER CO | Foreign currency derivatives | Other Nonoperating Income (Expense) | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | 159 | (82) | $ 0 | ||
SOUTHERN Co GAS | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | $ (3) | ||||
Gain (loss) reclassified from AOCI into income (effective portion) | (1) | ||||
SOUTHERN Co GAS | Energy-related derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 2 | (9) | |||
SOUTHERN Co GAS | Energy-related derivatives | Cost of Natural Gas | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (1) | $ (2) | |||
SOUTHERN Co GAS | Interest rate derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | (5) | ||||
SOUTHERN Co GAS | Interest rate derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | $ 0 | ||||
Predecessor | SOUTHERN Co GAS | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | $ (64) | 3 | |||
Gain (loss) reclassified from AOCI into income (effective portion) | (1) | (9) | |||
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | 0 | 3 | |||
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Cost of Natural Gas | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (1) | (10) | |||
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Other Operations And Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | (1) | ||||
Predecessor | SOUTHERN Co GAS | Interest rate derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gain (loss) on termination of interest rate derivatives | (64) | 0 | |||
Predecessor | SOUTHERN Co GAS | Interest rate derivatives | Interest Expense | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (loss) reclassified from AOCI into income (effective portion) | $ 0 | $ 2 |
Derivatives - Pre-Tax Effect130
Derivatives - Pre-Tax Effects of Derivatives Designated as Fair Value Hedging (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Parent Company | Interest rate derivatives | Interest Expense | Fair Value Hedging [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) on Fair Value Hedges Recognized in Earnings | $ (22) | $ (21) | $ 2 |
Derivatives - Pre-Tax Effect131
Derivatives - Pre-Tax Effects of Derivatives Not Designated as Hedging (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Energy-related derivatives | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | $ (86) | $ 38 | $ (2) | ||
Energy-related derivatives | Wholesale Electric Revenues | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | (4) | 2 | (5) | ||
Energy-related derivatives | Fuel | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | 0 | 0 | 3 | ||
Energy-related derivatives | Natural Gas Revenues | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | (80) | 33 | 0 | ||
Energy-related derivatives | Cost of Natural Gas | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | (2) | 3 | 0 | ||
Weather Derivative | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, gain (loss) on derivative, net | 23 | 6 | |||
SOUTHERN Co GAS | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, gain (loss) on derivative, net | $ 3 | 24 | |||
SOUTHERN Co GAS | Energy-related derivatives | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | 36 | (82) | |||
SOUTHERN Co GAS | Energy-related derivatives | Natural Gas Revenues | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | 33 | (80) | |||
SOUTHERN Co GAS | Energy-related derivatives | Cost of Natural Gas | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | $ 3 | (2) | |||
SOUTHERN Co GAS | Weather Derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, gain (loss) on derivative, net | $ 23 | ||||
Predecessor | SOUTHERN Co GAS | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, gain (loss) on derivative, net | $ (162) | (22) | |||
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | (63) | 50 | |||
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Natural Gas Revenues | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | (1) | 56 | |||
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Cost of Natural Gas | Not Designated as Hedging Instrument | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative instruments not designated as hedging iinstruments, gain (loss), net | (62) | (6) | |||
Predecessor | SOUTHERN Co GAS | Weather Derivatives | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative, gain (loss) on derivative, net | $ 6 | $ 3 | $ 12 |
Merger, Acquisitions, and Di132
Merger, Acquisitions, and Dispositions - Acquisitions and Dispositions Table (Details) $ in Millions | Jan. 26, 2018MW | Jul. 31, 2017MW | Jan. 06, 2017MW | Dec. 21, 2016MW | Dec. 01, 2016MW | Nov. 16, 2016 | Oct. 26, 2016MW | Aug. 26, 2016MW | Jul. 01, 2016MW | Jun. 30, 2016USD ($)MW | Apr. 07, 2016MW | Mar. 04, 2016MW | Feb. 11, 2016MW | Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($) | Feb. 10, 2016 | Dec. 31, 2015USD ($) | Aug. 31, 2015MW |
Purchase Price Allocation | |||||||||||||||||||
Goodwill | $ 6,251 | $ 6,251 | $ 6,268 | ||||||||||||||||
Total purchase price | 2,603 | 2,603 | |||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Assets | 109,697 | 109,697 | 111,005 | $ 78,318 | |||||||||||||||
PowerSecure International, Inc. | |||||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
Current assets | 172 | ||||||||||||||||||
Property, plant, and equipment | 46 | ||||||||||||||||||
Goodwill | 106 | ||||||||||||||||||
Intangible assets | 284 | ||||||||||||||||||
Other assets | 4 | ||||||||||||||||||
Current liabilities | (121) | ||||||||||||||||||
Long-term debt, including current portion | 48 | ||||||||||||||||||
Other liabilities | (14) | ||||||||||||||||||
Total purchase price | 429 | ||||||||||||||||||
SOUTHERN Co GAS | |||||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
Current assets | 1,557 | ||||||||||||||||||
Property, plant, and equipment | 10,108 | ||||||||||||||||||
Goodwill | 5,967 | ||||||||||||||||||
Intangible assets | 400 | ||||||||||||||||||
Regulatory assets | 1,118 | ||||||||||||||||||
Other assets | 229 | ||||||||||||||||||
Current liabilities | (2,201) | ||||||||||||||||||
Other liabilities | (4,742) | ||||||||||||||||||
Long-term debt | (4,261) | ||||||||||||||||||
Noncontrolling interest | (174) | ||||||||||||||||||
Total purchase price | 8,001 | ||||||||||||||||||
Rutherford | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 90.10% | ||||||||||||||||||
Series of Business Acquisitions | |||||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
CWIP | 2,354 | 2,354 | |||||||||||||||||
Property, plant, and equipment | 302 | 302 | |||||||||||||||||
Intangible assets | 128 | 128 | |||||||||||||||||
Other assets | 52 | 52 | |||||||||||||||||
Accounts payable | (16) | (16) | |||||||||||||||||
Long-term debt | (217) | (217) | |||||||||||||||||
Total purchase price | 2,345 | 2,345 | |||||||||||||||||
SOUTHERN POWER CO | |||||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
Total purchase price | 539 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Assets | 15,169 | 15,169 | $ 15,206 | ||||||||||||||||
SOUTHERN POWER CO | Boulder 1 | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 276 | 100 | |||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | 51.00% | |||||||||||||||||
Life output of plant | 12 years | 20 years | |||||||||||||||||
SOUTHERN POWER CO | Cactus Flats | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 148 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
SOUTHERN POWER CO | Bethel | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 276 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||
SOUTHERN POWER CO | 70SM1 8ME, LCC (Calipatria) | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 20 | ||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | 90.00% | |||||||||||||||||
Percentage of voting interests acquired | 10.00% | ||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||
SOUTHERN POWER CO | East Pecos [Member] | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 120 | ||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 15 years | ||||||||||||||||||
SOUTHERN POWER CO | Grant Plains | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 147 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||
SOUTHERN POWER CO | Mankato | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Capacity of natural gas facility | MW | 375 | ||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||
SOUTHERN POWER CO | Passadumkeag, LLC | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 42 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 15 years | ||||||||||||||||||
SOUTHERN POWER CO | Rutherford | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 74 | ||||||||||||||||||
Noncontrolling ownership percentage held by parent | 90.00% | 100.00% | |||||||||||||||||
Life output of plant | 15 years | ||||||||||||||||||
SOUTHERN POWER CO | Salt Fork | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 174 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
SOUTHERN POWER CO | Series of Business Acquisitions | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Contingent consideration | 281 | 281 | |||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
CWIP | $ 534 | ||||||||||||||||||
Intangible assets | 16 | ||||||||||||||||||
Other assets | 5 | ||||||||||||||||||
Accounts payable | (16) | ||||||||||||||||||
SOUTHERN POWER CO | Grant Wind, LLC | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 151 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||
SOUTHERN POWER CO | Henrietta | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 102 | ||||||||||||||||||
Noncontrolling ownership percentage held by parent | 51.00% | ||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||
SOUTHERN POWER CO | Lamesa | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 102 | ||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 15 years | ||||||||||||||||||
SOUTHERN POWER CO | Tyler Bluff | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 125 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||
SOUTHERN POWER CO | Wake Wind | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 257 | ||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 90.10% | ||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||
Turner Renewable Energy | 70SM1 8ME, LCC (Calipatria) | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 10.00% | ||||||||||||||||||
Turner Renewable Energy | Rutherford | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 10.00% | ||||||||||||||||||
Noncontrolling Interests | Series of Business Acquisitions | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Contingent consideration | 142 | 142 | |||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
Total purchase price | 258 | $ 258 | |||||||||||||||||
Predecessor | SOUTHERN Co GAS | |||||||||||||||||||
Purchase Price Allocation | |||||||||||||||||||
Current assets | $ 1,474 | ||||||||||||||||||
Property, plant, and equipment | 10,148 | ||||||||||||||||||
Goodwill | 1,813 | ||||||||||||||||||
Intangible assets | 101 | ||||||||||||||||||
Regulatory assets | 679 | ||||||||||||||||||
Other assets | 273 | ||||||||||||||||||
Current liabilities | (2,205) | ||||||||||||||||||
Other liabilities | (4,600) | ||||||||||||||||||
Long-term debt | (3,709) | ||||||||||||||||||
Noncontrolling interest | (41) | ||||||||||||||||||
Total purchase price | $ 3,933 | ||||||||||||||||||
Change in Basis | |||||||||||||||||||
Current assets | 83 | ||||||||||||||||||
Property, plant, and equipment | (40) | ||||||||||||||||||
Other intangible assets | 299 | ||||||||||||||||||
Goodwill | 4,154 | ||||||||||||||||||
Regulatory assets | 439 | ||||||||||||||||||
Other assets | (44) | ||||||||||||||||||
Current liabilities | 4 | ||||||||||||||||||
Other liabilities | (142) | ||||||||||||||||||
Long-term debt | (552) | ||||||||||||||||||
Contingently redeemable noncontrolling interest | (133) | ||||||||||||||||||
Total purchase price/equity | 4,068 | ||||||||||||||||||
Minimum | SOUTHERN POWER CO | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||
Minimum | SOUTHERN POWER CO | Cactus Flats | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||
Maximum | SOUTHERN POWER CO | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||
Maximum | SOUTHERN POWER CO | Cactus Flats | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 15 years | ||||||||||||||||||
Subsequent Event | SOUTHERN POWER CO | Gaskell West 1 | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 20 | ||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||
Grant County | SOUTHERN POWER CO | Grant Plains | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||
Donley County | SOUTHERN POWER CO | Salt Fork | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 14 years | ||||||||||||||||||
Gray County | SOUTHERN POWER CO | Salt Fork | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||
Senior Lien | SOUTHERN POWER CO | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Assets | 442 | ||||||||||||||||||
Class B Membership Interest | SOUTHERN POWER CO | Cactus Flats | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Class B Membership Interest | Subsequent Event | SOUTHERN POWER CO | Gaskell West 1 | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||
Acquisition Payable | SOUTHERN POWER CO | Series of Business Acquisitions | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Contingent consideration | $ 461 | $ 461 | |||||||||||||||||
Payables | SOUTHERN POWER CO | Series of Business Acquisitions | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Contingent consideration | $ 29 | ||||||||||||||||||
Allianz Risk Transfer (Bermuda) Ltd. | SOUTHERN POWER CO | Grant Plains | |||||||||||||||||||
Acquisition Information, by Acquisition [Abstract] | |||||||||||||||||||
Life output of plant | 10 years |
Merger, Acquisitions, and Di133
Merger, Acquisitions, and Dispositions - Pro Forma Consolidated Information (Details) - SOUTHERN Co GAS - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition [Line Items] | ||
Business acquisition, pro forma revenue | $ 21,791 | $ 21,430 |
Business acquisition, pro forma net income (loss) | $ 2,591 | $ 2,665 |
Business acquisition, pro forma earnings per share, basic | $ 2.70 | $ 2.85 |
Business acquisition, pro forma earnings per share, diluted | $ 2.68 | $ 2.84 |
Merger, Acquisitions, and Di134
Merger, Acquisitions, and Dispositions - Construction Projects (Details) - MW | Jul. 01, 2016 | Dec. 17, 2015 | Dec. 31, 2016 | Feb. 29, 2016 | Oct. 26, 2016 | Jul. 31, 2016 | Mar. 31, 2016 | Feb. 11, 2016 | Aug. 31, 2015 |
Rutherford | |||||||||
Business Acquisition [Line Items] | |||||||||
Noncontrolling ownership percentage held by parent | 90.10% | ||||||||
SOUTHERN POWER CO | Butler Solar LLC | |||||||||
Business Acquisition [Line Items] | |||||||||
Life output of plant | 30 years | ||||||||
SOUTHERN POWER CO | Butler Solar Farm, LLC | |||||||||
Business Acquisition [Line Items] | |||||||||
Life output of plant | 20 years | ||||||||
SOUTHERN POWER CO | Desert Stateline Holdings, LLC | |||||||||
Business Acquisition [Line Items] | |||||||||
Power of solar polycrystalline silicon facility | 299 | 299 | |||||||
Noncontrolling ownership percentage held by parent | 15.00% | 51.00% | |||||||
SOUTHERN POWER CO | RE Garland Holdings, LLC | |||||||||
Business Acquisition [Line Items] | |||||||||
Life output of plant | 20 years | ||||||||
SOUTHERN POWER CO | RE Garland A Holdings, LLC | |||||||||
Business Acquisition [Line Items] | |||||||||
Life output of plant | 15 years | ||||||||
SOUTHERN POWER CO | Rutherford | |||||||||
Business Acquisition [Line Items] | |||||||||
Power of solar polycrystalline silicon facility | 74 | ||||||||
Life output of plant | 15 years | ||||||||
Noncontrolling ownership percentage held by parent | 90.00% | 100.00% | |||||||
Turner Renewable Energy | Rutherford | |||||||||
Business Acquisition [Line Items] | |||||||||
Noncontrolling ownership percentage held by parent | 10.00% |
Merger, Acquisitions, and Di135
Merger, Acquisitions, and Dispositions - Textual (Details) $ / shares in Units, $ in Millions | Jan. 26, 2018MW | Mar. 31, 2017USD ($) | Oct. 26, 2016MW | Sep. 01, 2016USD ($) | Aug. 26, 2016MW | Jul. 01, 2016USD ($)$ / sharesMWshares | Feb. 11, 2016MW | Sep. 30, 2016USD ($)mi | May 31, 2016USD ($)$ / shares | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($)$ / sharesMWshares | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($)$ / sharesMWshares | Sep. 30, 2016USD ($)mi | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($)$ / sharesMWshares | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($)$ / sharesMWshares | Dec. 31, 2016USD ($)$ / sharesMWshares | Dec. 31, 2015USD ($) | Oct. 31, 2016USD ($) | Oct. 02, 2016 | Jul. 31, 2016MW | Feb. 10, 2016 | Aug. 31, 2015MW | |
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 539 | ||||||||||||||||||||||||||||
Revenue of acquiree | 15 | ||||||||||||||||||||||||||||
Net income of acquiree | 17 | ||||||||||||||||||||||||||||
Goodwill | $ 6,268 | $ 6,251 | $ 6,251 | 6,268 | $ 6,251 | ||||||||||||||||||||||||
Revenues | 5,629 | $ 6,201 | $ 5,430 | $ 5,771 | 5,181 | $ 6,264 | $ 4,459 | $ 3,992 | 23,031 | 19,896 | $ 17,489 | ||||||||||||||||||
Net income after dividends on preferred and preference stock | 496 | 1,069 | (1,381) | 658 | 197 | 1,139 | 623 | 489 | 842 | 2,448 | 2,367 | ||||||||||||||||||
2,018 | 95 | 95 | |||||||||||||||||||||||||||
Acquisitions payable | $ 5 | $ 489 | $ 489 | 5 | 489 | ||||||||||||||||||||||||
Contributions from noncontrolling interests | $ 79 | $ 618 | 567 | ||||||||||||||||||||||||||
Common stock, shares authorized | shares | 1,500,000,000 | 1,500,000,000 | 1,500,000,000 | 1,500,000,000 | 1,500,000,000 | ||||||||||||||||||||||||
Common stock, par value per share (in dollars per share) | $ / shares | $ 5 | $ 5 | $ 5 | $ 5 | $ 5 | ||||||||||||||||||||||||
Construction work in progress | $ 6,904 | $ 8,977 | $ 8,977 | $ 6,904 | $ 8,977 | ||||||||||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | 264 | ||||||||||||||||||||||||||||
Payments to acquire equity method investments | 152 | 1,444 | 0 | ||||||||||||||||||||||||||
PowerSecure International, Inc. | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Intangible assets | 284 | 284 | |||||||||||||||||||||||||||
Goodwill | 106 | 106 | |||||||||||||||||||||||||||
Business acquisition share price (in dollars per share) | $ / shares | $ 18.75 | ||||||||||||||||||||||||||||
Business combination, consideration transferred, equity interests issued and issuable | $ 429 | ||||||||||||||||||||||||||||
Current liabilities | 121 | 121 | |||||||||||||||||||||||||||
SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Intangible assets | 400 | 400 | |||||||||||||||||||||||||||
Goodwill | 5,967 | 5,967 | |||||||||||||||||||||||||||
Payments to acquire businesses | $ 8,000 | ||||||||||||||||||||||||||||
Current liabilities | 2,201 | 2,201 | |||||||||||||||||||||||||||
Common stock, shares authorized | shares | 100,000,000 | ||||||||||||||||||||||||||||
Preference stock, shares authorized | shares | 10,000,000 | ||||||||||||||||||||||||||||
Common stock, par value per share (in dollars per share) | $ / shares | $ 0.01 | ||||||||||||||||||||||||||||
Rutherford | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 90.10% | ||||||||||||||||||||||||||||
Series of Business Acquisitions | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Intangible assets | 128 | 128 | 128 | ||||||||||||||||||||||||||
SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Payments to acquire businesses | $ 2,300 | ||||||||||||||||||||||||||||
Finite-lived intangible asset, useful life | 19 years | ||||||||||||||||||||||||||||
Revenues | 478 | 618 | 529 | 450 | 389 | 500 | 373 | 315 | $ 2,075 | 1,577 | 1,390 | ||||||||||||||||||
Net income after dividends on preferred and preference stock | 795 | 124 | 82 | 70 | 23 | 176 | 89 | $ 50 | |||||||||||||||||||||
2,018 | 25 | 25 | |||||||||||||||||||||||||||
Acquisitions payable | $ 5 | $ 461 | $ 461 | 5 | 461 | ||||||||||||||||||||||||
Contributions from noncontrolling interests | $ 79 | $ 618 | 567 | ||||||||||||||||||||||||||
Common stock, shares authorized | shares | 1,000,000 | 1,000,000 | 1,000,000 | 1,000,000 | 1,000,000 | ||||||||||||||||||||||||
Common stock, par value per share (in dollars per share) | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | ||||||||||||||||||||||||
Construction work in progress | $ 511 | $ 398 | $ 398 | $ 511 | $ 398 | ||||||||||||||||||||||||
Capital contributions from parent company | $ (2) | 1,850 | 646 | ||||||||||||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | $ (743) | ||||||||||||||||||||||||||||
SOUTHERN POWER CO | Mankato Expansion [Member] | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Capacity of natural gas facility | MW | 345 | 345 | |||||||||||||||||||||||||||
SOUTHERN POWER CO | Desert Stateline Holdings, LLC | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 299 | 299 | |||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 15.00% | 51.00% | |||||||||||||||||||||||||||
SOUTHERN POWER CO | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 51 | ||||||||||||||||||||||||||||
SOUTHERN POWER CO | 70SM1 8ME, LCC (Calipatria) | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 20 | ||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | 90.00% | |||||||||||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||||||||||||
SOUTHERN POWER CO | Rutherford | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 74 | ||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 90.00% | 100.00% | |||||||||||||||||||||||||||
Life output of plant | 15 years | ||||||||||||||||||||||||||||
SOUTHERN POWER CO | Grant Plains | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||||||||||||
Life output of plant | 12 years | ||||||||||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 147 | ||||||||||||||||||||||||||||
SOUTHERN POWER CO | Mankato | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||||||||||||
Capacity of natural gas facility | MW | 375 | ||||||||||||||||||||||||||||
SOUTHERN POWER CO | Series of Business Acquisitions | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Intangible assets | $ 16 | $ 16 | |||||||||||||||||||||||||||
2,018 | 9 | 9 | 9 | ||||||||||||||||||||||||||
Contingent consideration | 281 | 281 | 281 | ||||||||||||||||||||||||||
SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Merger-related expenses | 41 | 0 | |||||||||||||||||||||||||||
Goodwill | 5,967 | 5,967 | 5,967 | 5,967 | $ 5,967 | ||||||||||||||||||||||||
Revenues | 1,079 | 565 | 716 | 1,560 | 1,109 | 543 | 1,652 | 3,920 | |||||||||||||||||||||
Net income after dividends on preferred and preference stock | (60) | $ 15 | $ 49 | $ 239 | $ 110 | $ 4 | $ 114 | 243 | |||||||||||||||||||||
2,018 | $ 58 | $ 58 | |||||||||||||||||||||||||||
Common stock, shares authorized | shares | 100,000,000 | 100 | 100 | 100,000,000 | 100 | ||||||||||||||||||||||||
Common stock, par value per share (in dollars per share) | $ / shares | $ 0.01 | $ 10,000 | $ 10,000 | $ 0.01 | $ 10,000 | ||||||||||||||||||||||||
Construction work in progress | $ 491 | $ 496 | $ 496 | $ 491 | $ 496 | ||||||||||||||||||||||||
Capital contributions from parent company | 1,094 | 117 | |||||||||||||||||||||||||||
Payments to acquire equity method investments | 1,444 | 145 | |||||||||||||||||||||||||||
SOUTHERN Co GAS | Southern Company | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Business acquisition share price (in dollars per share) | $ / shares | $ 66 | ||||||||||||||||||||||||||||
SOUTHERN Co GAS | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Goodwill | $ 6,000 | 6,000 | |||||||||||||||||||||||||||
Shares, authorized | shares | 110,000,000 | ||||||||||||||||||||||||||||
SOUTHERN Co GAS | Southern Natural Gas Company, LLC | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Pipeline infrastructure | mi | 7,000 | 7,000 | |||||||||||||||||||||||||||
Noncontrolling Interests | Series of Business Acquisitions | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Contingent consideration | $ 142 | $ 142 | $ 142 | ||||||||||||||||||||||||||
Invenergy | Rutherford | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 9.90% | ||||||||||||||||||||||||||||
Turner Renewable Energy | 70SM1 8ME, LCC (Calipatria) | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 10.00% | ||||||||||||||||||||||||||||
Turner Renewable Energy | Rutherford | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 10.00% | ||||||||||||||||||||||||||||
Southern Power, Turner Renewable Energy, SunPower, and Invenergy | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Payments to acquire businesses | $ 2,600 | ||||||||||||||||||||||||||||
Elizabethtown Gas | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Business combination, regulatory approval requirements, base rate case fling period | 3 years | ||||||||||||||||||||||||||||
Elkton Gas | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Business combination, regulatory approval requirements, base rate case fling period | 2 years | ||||||||||||||||||||||||||||
Class A Membership Interest | SOUTHERN POWER CO | Desert Stateline Holdings, LLC | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Percentage of entitled cash distributions | 66.00% | 66.00% | 66.00% | ||||||||||||||||||||||||||
Class A Membership Interest | SOUTHERN POWER CO | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | 100.00% | |||||||||||||||||||||||||||
Percentage of entitled cash distributions | 51.00% | 51.00% | |||||||||||||||||||||||||||
Class B Membership Interest | First Solar and Recurrent Energy | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | 100.00% | |||||||||||||||||||||||||||
Class B Membership Interest | First Solar | Desert Stateline Holdings, LLC | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Percentage of entitled cash distributions | 34.00% | 34.00% | 34.00% | ||||||||||||||||||||||||||
Class B Membership Interest | First Solar | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Percentage of entitled cash distributions | 49.00% | 49.00% | |||||||||||||||||||||||||||
Minimum | PowerSecure International, Inc. | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Finite-lived intangible asset, useful life | 1 year | ||||||||||||||||||||||||||||
Minimum | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Finite-lived intangible asset, useful life | 1 year | ||||||||||||||||||||||||||||
Minimum | SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||||||||||||
Minimum | SOUTHERN POWER CO | Series of Business Acquisitions | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Estimated Future Construction Payments | $ 385 | $ 385 | |||||||||||||||||||||||||||
Maximum | PowerSecure International, Inc. | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Finite-lived intangible asset, useful life | 26 years | ||||||||||||||||||||||||||||
Maximum | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Finite-lived intangible asset, useful life | 28 years | ||||||||||||||||||||||||||||
Maximum | SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||||||||||||
Maximum | SOUTHERN POWER CO | Series of Business Acquisitions | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Estimated Future Construction Payments | $ 430 | $ 430 | |||||||||||||||||||||||||||
Successor | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Goodwill | $ 30 | ||||||||||||||||||||||||||||
Successor | Elizabethtown Gas and Elkton Gas | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Business combination, regulatory approval requirements, required rate credit payments to customers | $ 18 | ||||||||||||||||||||||||||||
Predecessor | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Goodwill | $ 4,154 | ||||||||||||||||||||||||||||
Intangible assets | 101 | $ 101 | |||||||||||||||||||||||||||
Goodwill | 1,813 | 1,813 | |||||||||||||||||||||||||||
Current liabilities | 2,205 | 2,205 | |||||||||||||||||||||||||||
Predecessor | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Merger-related expenses | 56 | 44 | |||||||||||||||||||||||||||
Revenues | 571 | $ 1,334 | 1,905 | 3,941 | |||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | $ (51) | $ 182 | 131 | 353 | |||||||||||||||||||||||||
Payments to acquire equity method investments | $ 14 | 12 | |||||||||||||||||||||||||||
Subsequent Event | SOUTHERN POWER CO | Gaskell West 1 | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Power of solar polycrystalline silicon facility | MW | 20 | ||||||||||||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||||||||||||
Subsequent Event | Class B Membership Interest | SOUTHERN POWER CO | Gaskell West 1 | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 100.00% | ||||||||||||||||||||||||||||
SNG | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Capital contributions from parent company | $ 1,050 | ||||||||||||||||||||||||||||
Proceeds from contributions from affiliates | $ 360 | ||||||||||||||||||||||||||||
Equity method investment, difference between carrying amount and underlying equity | $ 700 | $ 700 | |||||||||||||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | $ 104 | ||||||||||||||||||||||||||||
Southstar | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Noncontrolling ownership percentage held by parent | 85.00% | ||||||||||||||||||||||||||||
Southern Natural Gas Company, LLC | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Ownership percentage, equity method investment | 50.00% | 50.00% | |||||||||||||||||||||||||||
Equity method investment, aggregate cost | $ 1,400 | $ 1,400 | |||||||||||||||||||||||||||
Payments to acquire equity method investments | $ 50 | ||||||||||||||||||||||||||||
Southstar | SOUTHERN Co GAS | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Ownership percentage of noncontrolling interest | 85.00% | 85.00% | |||||||||||||||||||||||||||
Agreement to purchase remaining interest | $ 160 | ||||||||||||||||||||||||||||
Southstar | Piedmont | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Ownership percentage of noncontrolling interest | 15.00% | 15.00% | |||||||||||||||||||||||||||
Siemens Wind Power, Inc. And Vestas-American Wind Technology, Inc. [Member] | SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 900 | 900 | |||||||||||||||||||||||||||
Renewable Energy Systems Americas, Inc. [Member] | SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 3,000 | 3,000 | 3,000 | ||||||||||||||||||||||||||
Allianz Risk Transfer (Bermuda) Ltd. | SOUTHERN POWER CO | Grant Plains | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Life output of plant | 10 years | ||||||||||||||||||||||||||||
Wind Generating Facility | SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Project Qualification for Production Tax Credits, Percentage | 80.00% | 100.00% | |||||||||||||||||||||||||||
Grant County | SOUTHERN POWER CO | Grant Plains | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Life output of plant | 20 years | ||||||||||||||||||||||||||||
Noncontrolling Interests | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Contributions from noncontrolling interests | $ 79 | $ 618 | 567 | ||||||||||||||||||||||||||
Noncontrolling Interests | SOUTHERN POWER CO | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Contributions from noncontrolling interests | [1] | 79 | $ 618 | $ 567 | |||||||||||||||||||||||||
Subsidiaries | Scenario, Forecast | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Proceeds from sale of oil and gas property and equipment | $ 1,700 | ||||||||||||||||||||||||||||
Construction in Progress [Member] | Series of Business Acquisitions | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||
Construction and Development Costs | $ 188 | ||||||||||||||||||||||||||||
[1] | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. |
Segment and Related Informat136
Segment and Related Information - Textuals (Details) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017USD ($)statesegment | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)statesegment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Segment Reporting Information [Line Items] | ||||||||||||
Number of traditional operating companies | segment | 4 | 4 | ||||||||||
Revenues | $ 5,629 | $ 6,201 | $ 5,430 | $ 5,771 | $ 5,181 | $ 6,264 | $ 4,459 | $ 3,992 | $ 23,031 | $ 19,896 | $ 17,489 | |
Natural gas revenues | $ 3,791 | 1,596 | 0 | |||||||||
Traditional Operating Companies | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Number of states in which entity operates | state | 4 | 4 | ||||||||||
SOUTHERN Co GAS | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Number of reportable segments | segment | 4 | |||||||||||
Number of states in which entity operates | state | 7 | 7 | ||||||||||
Revenues | $ 1,079 | $ 565 | $ 716 | $ 1,560 | $ 1,109 | $ 543 | $ 1,652 | $ 3,920 | ||||
Natural gas revenues | $ 1,596 | 3,791 | ||||||||||
Southern Natural Gas Company, LLC | SOUTHERN Co GAS | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Ownership percentage, equity method investment | 50.00% | |||||||||||
SOUTHERN POWER CO | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 392 | 419 | $ 417 | |||||||||
Natural gas revenues | 119 | 17 | ||||||||||
SOUTHERN Co GAS | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Natural gas revenues | $ 23 | $ 11 |
Segment and Related Informat137
Segment and Related Information - Financial Data for Business Segments and Products and Services (Details) - USD ($) | 3 Months Ended | 6 Months Ended | 10 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Oct. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Financial data for business segments | ||||||||||||||
Operating revenues | $ 5,629,000,000 | $ 6,201,000,000 | $ 5,430,000,000 | $ 5,771,000,000 | $ 5,181,000,000 | $ 6,264,000,000 | $ 4,459,000,000 | $ 3,992,000,000 | $ 23,031,000,000 | $ 19,896,000,000 | $ 17,489,000,000 | |||
Depreciation and amortization | 3,010,000,000 | 2,502,000,000 | 2,034,000,000 | |||||||||||
Depreciation and amortization | 3,457,000,000 | 2,923,000,000 | 2,395,000,000 | |||||||||||
Operating Income (Loss) | 794,000,000 | 2,045,000,000 | (1,594,000,000) | 1,306,000,000 | 587,000,000 | 1,917,000,000 | 1,185,000,000 | 940,000,000 | 2,551,000,000 | 4,629,000,000 | 4,282,000,000 | |||
Earnings from equity method investments | $ 15,000,000 | 106,000,000 | 59,000,000 | 0 | ||||||||||
Interest income | 26,000,000 | 20,000,000 | 23,000,000 | |||||||||||
Interest expense | 1,694,000,000 | 1,317,000,000 | 840,000,000 | |||||||||||
Income taxes | 142,000,000 | 951,000,000 | 1,194,000,000 | |||||||||||
Segment net income (loss) | 496,000,000 | 1,069,000,000 | (1,381,000,000) | 658,000,000 | 197,000,000 | 1,139,000,000 | 623,000,000 | 489,000,000 | 842,000,000 | 2,448,000,000 | 2,367,000,000 | |||
Gross property additions | 5,984,000,000 | 7,624,000,000 | 6,169,000,000 | |||||||||||
Total assets | 111,005,000,000 | 109,697,000,000 | $ 109,697,000,000 | 111,005,000,000 | 109,697,000,000 | 78,318,000,000 | ||||||||
Segment and Related Information (Textual) [Abstract] | ||||||||||||||
Estimated loss on Kemper IGCC | 3,362,000,000 | 428,000,000 | 365,000,000 | |||||||||||
Unamortized debt issuance expense | 226,000,000 | 213,000,000 | 213,000,000 | 226,000,000 | 213,000,000 | |||||||||
Kemper IGCC | ||||||||||||||
Segment and Related Information (Textual) [Abstract] | ||||||||||||||
After tax charge to income | 185,000,000 | 21,000,000 | 2,100,000,000 | 67,000,000 | 127,000,000 | 54,000,000 | 50,000,000 | 33,000,000 | 2,400,000,000 | 264,000,000 | 226,000,000 | |||
Electric Utilities | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 18,540,000,000 | 17,941,000,000 | 17,442,000,000 | |||||||||||
Depreciation and amortization | 2,457,000,000 | 2,233,000,000 | 2,020,000,000 | |||||||||||
Earnings from equity method investments | 1,000,000 | 2,000,000 | 1,000,000 | |||||||||||
Interest income | 21,000,000 | 13,000,000 | 22,000,000 | |||||||||||
Interest expense | 1,011,000,000 | 931,000,000 | 774,000,000 | |||||||||||
Income taxes | 82,000,000 | 1,091,000,000 | 1,326,000,000 | |||||||||||
Segment net income (loss) | 878,000,000 | 2,571,000,000 | 2,401,000,000 | |||||||||||
Gross property additions | 4,104,000,000 | 6,966,000,000 | 6,129,000,000 | |||||||||||
Total assets | 87,085,000,000 | 86,994,000,000 | 86,994,000,000 | 87,085,000,000 | 86,994,000,000 | 77,560,000,000 | ||||||||
SOUTHERN POWER CO | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 392,000,000 | 419,000,000 | 417,000,000 | |||||||||||
SOUTHERN POWER CO | Electric Utilities | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 2,075,000,000 | 1,577,000,000 | 1,390,000,000 | |||||||||||
Depreciation and amortization | 503,000,000 | 352,000,000 | 248,000,000 | |||||||||||
Earnings from equity method investments | 0 | 0 | 0 | |||||||||||
Interest income | 7,000,000 | 7,000,000 | 2,000,000 | |||||||||||
Interest expense | 191,000,000 | 117,000,000 | 77,000,000 | |||||||||||
Income taxes | (939,000,000) | (195,000,000) | 21,000,000 | |||||||||||
Segment net income (loss) | 1,071,000,000 | 338,000,000 | 215,000,000 | |||||||||||
Gross property additions | 268,000,000 | 2,114,000,000 | 1,005,000,000 | |||||||||||
Total assets | 15,206,000,000 | 15,169,000,000 | 15,169,000,000 | 15,206,000,000 | 15,169,000,000 | 8,905,000,000 | ||||||||
SOUTHERN Co GAS | Electric Utilities | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 3,920,000,000 | 1,652,000,000 | 0 | |||||||||||
Depreciation and amortization | 501,000,000 | 238,000,000 | 0 | |||||||||||
Earnings from equity method investments | 106,000,000 | 60,000,000 | 0 | |||||||||||
Interest income | 3,000,000 | 2,000,000 | 0 | |||||||||||
Interest expense | 200,000,000 | 81,000,000 | 0 | |||||||||||
Income taxes | 367,000,000 | 76,000,000 | 0 | |||||||||||
Segment net income (loss) | 243,000,000 | 114,000,000 | 0 | |||||||||||
Gross property additions | 1,525,000,000 | 618,000,000 | 0 | |||||||||||
Total assets | 22,987,000,000 | 21,853,000,000 | 21,853,000,000 | 22,987,000,000 | 21,853,000,000 | 0 | ||||||||
Traditional Operating Companies | Electric Utilities | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 16,884,000,000 | 16,803,000,000 | 16,491,000,000 | |||||||||||
Depreciation and amortization | 1,954,000,000 | 1,881,000,000 | 1,772,000,000 | |||||||||||
Earnings from equity method investments | 1,000,000 | 2,000,000 | 1,000,000 | |||||||||||
Interest income | 14,000,000 | 6,000,000 | 19,000,000 | |||||||||||
Interest expense | 820,000,000 | 814,000,000 | 697,000,000 | |||||||||||
Income taxes | 1,021,000,000 | 1,286,000,000 | 1,305,000,000 | |||||||||||
Segment net income (loss) | (193,000,000) | 2,233,000,000 | 2,186,000,000 | |||||||||||
Gross property additions | 3,836,000,000 | 4,852,000,000 | 5,124,000,000 | |||||||||||
Total assets | 72,204,000,000 | 72,141,000,000 | 72,141,000,000 | 72,204,000,000 | 72,141,000,000 | 69,052,000,000 | ||||||||
All Other [Member] | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 741,000,000 | 463,000,000 | 152,000,000 | |||||||||||
Depreciation and amortization | 52,000,000 | 31,000,000 | 14,000,000 | |||||||||||
Earnings from equity method investments | (1,000,000) | (3,000,000) | (1,000,000) | |||||||||||
Interest income | 11,000,000 | 20,000,000 | 6,000,000 | |||||||||||
Interest expense | 490,000,000 | 317,000,000 | 69,000,000 | |||||||||||
Income taxes | (307,000,000) | (216,000,000) | (132,000,000) | |||||||||||
Segment net income (loss) | (279,000,000) | (230,000,000) | (32,000,000) | |||||||||||
Gross property additions | 355,000,000 | 41,000,000 | 40,000,000 | |||||||||||
Total assets | 2,552,000,000 | 2,474,000,000 | 2,474,000,000 | 2,552,000,000 | 2,474,000,000 | 1,819,000,000 | ||||||||
Intersegment Eliminations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | (170,000,000) | (160,000,000) | (105,000,000) | |||||||||||
Depreciation and amortization | 0 | 0 | 0 | |||||||||||
Earnings from equity method investments | 0 | 0 | 0 | |||||||||||
Interest income | (9,000,000) | (15,000,000) | (5,000,000) | |||||||||||
Interest expense | (7,000,000) | (12,000,000) | (3,000,000) | |||||||||||
Income taxes | 0 | 0 | 0 | |||||||||||
Segment net income (loss) | 0 | (7,000,000) | (2,000,000) | |||||||||||
Gross property additions | 0 | (1,000,000) | 0 | |||||||||||
Total assets | (1,619,000,000) | (1,624,000,000) | (1,624,000,000) | (1,619,000,000) | (1,624,000,000) | (1,061,000,000) | ||||||||
Intersegment Eliminations | Electric Utilities | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | (419,000,000) | (439,000,000) | (439,000,000) | |||||||||||
Depreciation and amortization | 0 | 0 | 0 | |||||||||||
Earnings from equity method investments | 0 | 0 | 0 | |||||||||||
Interest income | 0 | 0 | 1,000,000 | |||||||||||
Interest expense | 0 | 0 | 0 | |||||||||||
Income taxes | 0 | 0 | 0 | |||||||||||
Segment net income (loss) | 0 | 0 | 0 | |||||||||||
Gross property additions | 0 | 0 | 0 | |||||||||||
Total assets | (325,000,000) | (316,000,000) | (316,000,000) | (325,000,000) | (316,000,000) | (397,000,000) | ||||||||
GULF POWER CO | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 372,000,000 | 437,000,000 | 357,000,000 | 350,000,000 | 349,000,000 | 436,000,000 | 365,000,000 | 335,000,000 | 1,516,000,000 | 1,485,000,000 | 1,483,000,000 | |||
Depreciation and amortization | 137,000,000 | 172,000,000 | 141,000,000 | |||||||||||
Depreciation and amortization | 149,000,000 | 179,000,000 | 152,000,000 | |||||||||||
Operating Income (Loss) | 53,000,000 | 115,000,000 | 75,000,000 | 46,000,000 | 54,000,000 | 90,000,000 | 74,000,000 | 65,000,000 | 289,000,000 | 283,000,000 | 290,000,000 | |||
Interest expense | 50,000,000 | 47,000,000 | 49,000,000 | |||||||||||
Income taxes | 90,000,000 | 91,000,000 | 92,000,000 | |||||||||||
Segment net income (loss) | 19,000,000 | 63,000,000 | 35,000,000 | 18,000,000 | 23,000,000 | 45,000,000 | 34,000,000 | 29,000,000 | 135,000,000 | 131,000,000 | 148,000,000 | |||
Total assets | 4,797,000,000 | 4,822,000,000 | 4,822,000,000 | 4,797,000,000 | 4,822,000,000 | |||||||||
Segment and Related Information (Textual) [Abstract] | ||||||||||||||
Loss on Plant Scherer Unit 3 | 33,000,000 | 0 | 0 | |||||||||||
After tax charge to income | 0 | |||||||||||||
Unamortized debt issuance expense | 9,000,000 | 7,000,000 | 7,000,000 | 9,000,000 | 7,000,000 | |||||||||
SOUTHERN Co GAS | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 1,079,000,000 | 565,000,000 | 716,000,000 | 1,560,000,000 | 1,109,000,000 | 543,000,000 | 1,652,000,000 | 3,920,000,000 | ||||||
Depreciation and amortization | 238,000,000 | 501,000,000 | ||||||||||||
Operating Income (Loss) | 110,000,000 | 68,000,000 | 96,000,000 | 391,000,000 | 185,000,000 | 12,000,000 | 197,000,000 | 665,000,000 | ||||||
Earnings from equity method investments | 60,000,000 | 106,000,000 | ||||||||||||
EBIT | 129,000,000 | 118,000,000 | 128,000,000 | 435,000,000 | 221,000,000 | 50,000,000 | ||||||||
Interest expense | 81,000,000 | 200,000,000 | ||||||||||||
Income taxes | 76,000,000 | 367,000,000 | ||||||||||||
Segment net income (loss) | (60,000,000) | $ 15,000,000 | $ 49,000,000 | $ 239,000,000 | 110,000,000 | $ 4,000,000 | 114,000,000 | 243,000,000 | ||||||
Gross property additions | 632,000,000 | 1,508,000,000 | ||||||||||||
Total assets | 22,987,000,000 | 21,853,000,000 | 21,853,000,000 | 22,987,000,000 | 21,853,000,000 | |||||||||
Segment and Related Information (Textual) [Abstract] | ||||||||||||||
Loss on Plant Scherer Unit 3 | 0 | |||||||||||||
SOUTHERN Co GAS | Operating Segments | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 1,751,000,000 | 4,144,000,000 | ||||||||||||
Depreciation and amortization | 230,000,000 | 473,000,000 | ||||||||||||
Operating Income (Loss) | 240,000,000 | 702,000,000 | ||||||||||||
Earnings from equity method investments | 58,000,000 | 103,000,000 | ||||||||||||
Interest expense | 125,000,000 | 198,000,000 | ||||||||||||
Income taxes | 71,000,000 | 263,000,000 | ||||||||||||
Segment net income (loss) | 116,000,000 | 383,000,000 | ||||||||||||
Gross property additions | 621,000,000 | 1,474,000,000 | ||||||||||||
Total assets | 24,842,000,000 | 24,875,000,000 | 24,875,000,000 | 24,842,000,000 | 24,875,000,000 | |||||||||
SOUTHERN Co GAS | Operating Segments | Gas Distribution Operations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 1,342,000,000 | 3,207,000,000 | ||||||||||||
Depreciation and amortization | 185,000,000 | 391,000,000 | ||||||||||||
Operating Income (Loss) | 222,000,000 | 650,000,000 | ||||||||||||
Earnings from equity method investments | 0 | 0 | ||||||||||||
Interest expense | 105,000,000 | 153,000,000 | ||||||||||||
Income taxes | 51,000,000 | 178,000,000 | ||||||||||||
Segment net income (loss) | 77,000,000 | 353,000,000 | ||||||||||||
Gross property additions | 561,000,000 | 1,330,000,000 | ||||||||||||
Total assets | 19,358,000,000 | 19,453,000,000 | 19,453,000,000 | 19,358,000,000 | 19,453,000,000 | |||||||||
SOUTHERN Co GAS | Operating Segments | Gas Marketing Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 354,000,000 | 860,000,000 | ||||||||||||
Depreciation and amortization | 35,000,000 | 62,000,000 | ||||||||||||
Operating Income (Loss) | 27,000,000 | 113,000,000 | ||||||||||||
Earnings from equity method investments | 0 | 0 | ||||||||||||
Interest expense | 1,000,000 | 5,000,000 | ||||||||||||
Income taxes | 7,000,000 | 24,000,000 | ||||||||||||
Segment net income (loss) | 19,000,000 | 84,000,000 | ||||||||||||
Gross property additions | 5,000,000 | 9,000,000 | ||||||||||||
Total assets | 2,147,000,000 | 2,084,000,000 | 2,084,000,000 | 2,147,000,000 | 2,084,000,000 | |||||||||
SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 24,000,000 | 6,000,000 | ||||||||||||
Cost of revenue | 6,116,000,000 | 6,627,000,000 | ||||||||||||
Depreciation and amortization | 1,000,000 | 2,000,000 | ||||||||||||
Operating Income (Loss) | (2,000,000) | (51,000,000) | ||||||||||||
Earnings from equity method investments | 0 | 0 | ||||||||||||
Interest expense | 3,000,000 | 7,000,000 | ||||||||||||
Income taxes | (3,000,000) | 0 | ||||||||||||
Segment net income (loss) | 0 | (57,000,000) | ||||||||||||
Gross property additions | 1,000,000 | 1,000,000 | ||||||||||||
Total assets | 1,096,000,000 | 1,127,000,000 | 1,127,000,000 | 1,096,000,000 | 1,127,000,000 | |||||||||
SOUTHERN Co GAS | Operating Segments | Gas Midstream Operations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 31,000,000 | 71,000,000 | ||||||||||||
Depreciation and amortization | 9,000,000 | 18,000,000 | ||||||||||||
Operating Income (Loss) | (7,000,000) | (10,000,000) | ||||||||||||
Earnings from equity method investments | 58,000,000 | 103,000,000 | ||||||||||||
Interest expense | 16,000,000 | 33,000,000 | ||||||||||||
Income taxes | 16,000,000 | 61,000,000 | ||||||||||||
Segment net income (loss) | 20,000,000 | 3,000,000 | ||||||||||||
Gross property additions | 54,000,000 | 134,000,000 | ||||||||||||
Total assets | 2,241,000,000 | 2,211,000,000 | 2,211,000,000 | 2,241,000,000 | 2,211,000,000 | |||||||||
SOUTHERN Co GAS | Operating Segments | All Other [Member] | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 3,000,000 | 10,000,000 | ||||||||||||
Depreciation and amortization | 8,000,000 | 28,000,000 | ||||||||||||
Operating Income (Loss) | (43,000,000) | (37,000,000) | ||||||||||||
Earnings from equity method investments | 2,000,000 | 3,000,000 | ||||||||||||
Interest expense | (44,000,000) | 2,000,000 | ||||||||||||
Income taxes | 5,000,000 | 104,000,000 | ||||||||||||
Segment net income (loss) | (2,000,000) | (140,000,000) | ||||||||||||
Gross property additions | 11,000,000 | 34,000,000 | ||||||||||||
Total assets | 12,184,000,000 | 11,145,000,000 | 11,145,000,000 | 12,184,000,000 | 11,145,000,000 | |||||||||
SOUTHERN Co GAS | Intersegment Eliminations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | (102,000,000) | (234,000,000) | ||||||||||||
Depreciation and amortization | 0 | 0 | ||||||||||||
Operating Income (Loss) | 0 | 0 | ||||||||||||
Earnings from equity method investments | 0 | 0 | ||||||||||||
Interest expense | 0 | 0 | ||||||||||||
Income taxes | 0 | 0 | ||||||||||||
Segment net income (loss) | 0 | 0 | ||||||||||||
Gross property additions | 0 | 0 | ||||||||||||
Total assets | $ (14,039,000,000) | $ (14,167,000,000) | (14,167,000,000) | (14,039,000,000) | $ (14,167,000,000) | |||||||||
Predecessor | SOUTHERN Co GAS | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 571,000,000 | 1,334,000,000 | $ 1,905,000,000 | 3,941,000,000 | ||||||||||
Depreciation and amortization | 206,000,000 | 397,000,000 | ||||||||||||
Operating Income (Loss) | (27,000,000) | 348,000,000 | 321,000,000 | 746,000,000 | ||||||||||
Earnings from equity method investments | 2,000,000 | 6,000,000 | ||||||||||||
EBIT | (23,000,000) | 351,000,000 | 328,000,000 | 761,000,000 | ||||||||||
Interest expense | 96,000,000 | 175,000,000 | ||||||||||||
Income taxes | 87,000,000 | 213,000,000 | ||||||||||||
Segment net income (loss) | $ (51,000,000) | $ 182,000,000 | 131,000,000 | 353,000,000 | ||||||||||
Gross property additions | 548,000,000 | 1,027,000,000 | ||||||||||||
Total assets | 14,754,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Operating Segments | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 2,003,000,000 | 4,141,000,000 | ||||||||||||
Depreciation and amortization | 199,000,000 | 380,000,000 | ||||||||||||
Operating Income (Loss) | 382,000,000 | 809,000,000 | ||||||||||||
EBIT | 388,000,000 | 820,000,000 | ||||||||||||
Gross property additions | 532,000,000 | 993,000,000 | ||||||||||||
Total assets | 14,832,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Operating Segments | Gas Distribution Operations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 1,575,000,000 | 3,049,000,000 | ||||||||||||
Depreciation and amortization | 178,000,000 | 336,000,000 | ||||||||||||
Operating Income (Loss) | 351,000,000 | 571,000,000 | ||||||||||||
EBIT | 353,000,000 | 581,000,000 | ||||||||||||
Gross property additions | 484,000,000 | 957,000,000 | ||||||||||||
Total assets | 12,519,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Operating Segments | Gas Marketing Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 435,000,000 | 835,000,000 | ||||||||||||
Depreciation and amortization | 11,000,000 | 25,000,000 | ||||||||||||
Operating Income (Loss) | 109,000,000 | 152,000,000 | ||||||||||||
EBIT | 109,000,000 | 152,000,000 | ||||||||||||
Gross property additions | 4,000,000 | 7,000,000 | ||||||||||||
Total assets | 686,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | (32,000,000) | 202,000,000 | ||||||||||||
Cost of revenue | 2,675,000,000 | 6,492,000,000 | ||||||||||||
Depreciation and amortization | 1,000,000 | 1,000,000 | ||||||||||||
Operating Income (Loss) | (69,000,000) | 112,000,000 | ||||||||||||
EBIT | (68,000,000) | 110,000,000 | ||||||||||||
Gross property additions | 1,000,000 | 2,000,000 | ||||||||||||
Total assets | 935,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Operating Segments | Gas Midstream Operations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 25,000,000 | 55,000,000 | ||||||||||||
Depreciation and amortization | 9,000,000 | 18,000,000 | ||||||||||||
Operating Income (Loss) | (9,000,000) | (26,000,000) | ||||||||||||
EBIT | (6,000,000) | (23,000,000) | ||||||||||||
Gross property additions | 43,000,000 | 27,000,000 | ||||||||||||
Total assets | 692,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Operating Segments | All Other [Member] | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 4,000,000 | 11,000,000 | ||||||||||||
Depreciation and amortization | 7,000,000 | 17,000,000 | ||||||||||||
Operating Income (Loss) | (61,000,000) | (63,000,000) | ||||||||||||
EBIT | (60,000,000) | (59,000,000) | ||||||||||||
Gross property additions | 16,000,000 | 34,000,000 | ||||||||||||
Total assets | 9,662,000,000 | |||||||||||||
Predecessor | SOUTHERN Co GAS | Intersegment Eliminations | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | (102,000,000) | (211,000,000) | ||||||||||||
Depreciation and amortization | 0 | 0 | ||||||||||||
Operating Income (Loss) | 0 | 0 | ||||||||||||
EBIT | 0 | 0 | ||||||||||||
Gross property additions | 0 | 0 | ||||||||||||
Total assets | (9,740,000,000) | |||||||||||||
Third Party Gross Revenues | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 5,807,000,000 | 6,152,000,000 | ||||||||||||
Third Party Gross Revenues | Predecessor | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 2,500,000,000 | 6,286,000,000 | ||||||||||||
Intercompany Revenues | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 333,000,000 | 481,000,000 | ||||||||||||
Intercompany Revenues | Predecessor | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | 143,000,000 | 408,000,000 | ||||||||||||
Total Gross Revenues | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | $ 6,140,000,000 | $ 6,633,000,000 | ||||||||||||
Total Gross Revenues | Predecessor | SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | ||||||||||||||
Financial data for business segments | ||||||||||||||
Operating revenues | $ 2,643,000,000 | $ 6,694,000,000 |
Segment and Related Informat138
Segment and Related Information - Electric Utilities' Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenue from External Customer [Line Items] | |||||||||||
Electric utilities revenues | $ 5,629 | $ 6,201 | $ 5,430 | $ 5,771 | $ 5,181 | $ 6,264 | $ 4,459 | $ 3,992 | $ 23,031 | $ 19,896 | $ 17,489 |
Retail | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Electric utilities revenues | 15,330 | 15,234 | 14,987 | ||||||||
Wholesale | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Electric utilities revenues | 2,426 | 1,926 | 1,798 | ||||||||
Other Electric Revenue [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Electric utilities revenues | 784 | 781 | 657 | ||||||||
Electric Utilities | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Electric utilities revenues | $ 18,540 | $ 17,941 | $ 17,442 |
Segment and Related Informat139
Segment and Related Information - Gas Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | ||
Gas revenue | $ 3,920 | $ 1,652 |
Gas Distribution Operations | ||
Segment Reporting Information [Line Items] | ||
Gas revenue | 3,024 | 1,266 |
Gas Marketing Services | ||
Segment Reporting Information [Line Items] | ||
Gas revenue | 860 | 354 |
Other Gas Revenue | ||
Segment Reporting Information [Line Items] | ||
Gas revenue | $ 36 | $ 32 |
Noncontrolling Interest - Textu
Noncontrolling Interest - Textuals (Details) - USD ($) | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Oct. 31, 2017 | Apr. 30, 2017 | Dec. 31, 2014 | |
Redeemable Noncontrolling Interest [Line Items] | ||||||
Reclassification from redeemable noncontrolling interest | $ 0 | $ (164,000,000) | ||||
SOUTHERN POWER CO | ||||||
Redeemable Noncontrolling Interest [Line Items] | ||||||
Redeemable put option | 0 | 164,000,000 | $ 43,000,000 | $ 39,000,000 | ||
Net income attributable to redeemable noncontrolling interests | 2,000,000 | $ 4,000,000 | $ 2,000,000 | |||
Reclassification from redeemable noncontrolling interest | $ 0 | |||||
SunPower Corp | SOUTHERN POWER CO | ||||||
Redeemable Noncontrolling Interest [Line Items] | ||||||
Reclassification from redeemable noncontrolling interest | $ 114,000,000 | |||||
Recalssification to nonredeemable noncontrolling interest | $ 114,000,000 | |||||
Turner Renewable Energy | SOUTHERN POWER CO | ||||||
Redeemable Noncontrolling Interest [Line Items] | ||||||
Ownership percentage of noncontrolling interest | 10.00% |
Noncontrolling Interest - Redee
Noncontrolling Interest - Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Noncontrolling Interest [Roll Forward] | |||
Purchase of membership interests from noncontrolling interests | $ (129) | ||
SOUTHERN POWER CO | |||
Noncontrolling Interest [Roll Forward] | |||
Beginning balance | $ 164 | 43 | $ 39 |
Net income attributable to redeemable noncontrolling interests | 2 | 4 | 2 |
Distributions to redeemable noncontrolling interests | (2) | (1) | 0 |
Capital contributions from redeemable noncontrolling interests | 2 | 118 | 2 |
Redeemable Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests | 59 | 0 | |
Purchase of membership interests from noncontrolling interests | (129) | 0 | |
Reclassification to non-redeemable noncontrolling interests | (114) | 0 | 0 |
Change in fair value of redeemable noncontrolling interests | 7 | 0 | 0 |
Ending balance | $ 0 | $ 164 | $ 43 |
Noncontrolling Interest - Net I
Noncontrolling Interest - Net Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Noncontrolling Interest [Line Items] | |||
Net income | $ 926 | $ 2,529 | $ 2,435 |
Less: Net income attributable to noncontrolling interests | (44) | (32) | (12) |
SOUTHERN POWER CO | |||
Noncontrolling Interest [Line Items] | |||
Net income | 1,117 | 374 | 229 |
Less: Net income attributable to noncontrolling interests | (44) | (32) | (12) |
Less: Net income attributable to redeemable noncontrolling interests | 2 | 4 | 2 |
Net income attributable to the Company | 1,071 | 338 | 215 |
Noncontrolling Interests | SOUTHERN POWER CO | |||
Noncontrolling Interest [Line Items] | |||
Less: Net income attributable to noncontrolling interests | $ 44 | $ 32 | $ 12 |
Quarterly Financial Informat143
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | 65 Months Ended | |||||||||||
Jun. 30, 2017 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | May 31, 2017 | |
Quarterly Financial Information [Line Items] | ||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | $ 264 | |||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 5,629 | $ 6,201 | $ 5,430 | $ 5,771 | $ 5,181 | $ 6,264 | $ 4,459 | $ 3,992 | $ 23,031 | $ 19,896 | $ 17,489 | |||||
Operating income (loss) | 794 | 2,045 | (1,594) | 1,306 | 587 | 1,917 | 1,185 | 940 | 2,551 | 4,629 | 4,282 | |||||
Income taxes | 142 | 951 | 1,194 | |||||||||||||
Net income after dividends on preferred and preference stock | $ 496 | $ 1,069 | $ (1,381) | $ 658 | $ 197 | $ 1,139 | $ 623 | $ 489 | $ 842 | $ 2,448 | $ 2,367 | |||||
Basic (in dollars per share) | $ 0.49 | $ 1.07 | $ (1.38) | $ 0.66 | $ 0.20 | $ 1.18 | $ 0.67 | $ 0.53 | $ 0.84 | $ 2.57 | $ 2.60 | |||||
Diluted (in dollars per share) | 0.49 | 1.06 | (1.37) | 0.66 | 0.20 | 1.17 | 0.66 | 0.53 | 0.84 | 2.55 | 2.59 | |||||
Cash dividends (in dollars per share) | 0.58 | 0.58 | 0.58 | 0.56 | 0.5600 | 0.5600 | 0.5600 | 0.5425 | $ 2.3000 | $ 2.2225 | $ 2.1525 | |||||
Trading price range, high, per common share (in dollars per share) | 53.51 | 50.80 | 51.97 | 51.47 | 52.23 | 54.64 | 53.64 | 51.73 | ||||||||
Trading price range, low, per common share (in dollars per share) | $ 47.92 | $ 46.71 | $ 47.87 | $ 47.57 | $ 46.20 | $ 50 | $ 47.62 | $ 46 | ||||||||
GEORGIA POWER CO | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | $ 1,884 | $ 2,546 | $ 2,048 | $ 1,832 | $ 1,762 | $ 2,698 | $ 2,051 | $ 1,872 | $ 8,310 | $ 8,383 | $ 8,326 | |||||
Operating income (loss) | 470 | 1,034 | 639 | 501 | 258 | 1,054 | 656 | 509 | 2,644 | 2,477 | 2,348 | |||||
Income taxes | 830 | 780 | 769 | |||||||||||||
Net income after dividends on preferred and preference stock | 227 | 580 | 347 | 260 | 113 | 599 | 349 | 269 | 1,414 | 1,330 | 1,260 | |||||
ALABAMA POWER CO | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 1,433 | 1,740 | 1,484 | 1,382 | 1,329 | 1,785 | 1,444 | 1,331 | 6,039 | 5,889 | 5,768 | |||||
Operating income (loss) | 268 | 616 | 454 | 376 | 252 | 650 | 430 | 333 | 1,714 | 1,665 | 1,563 | |||||
Income taxes | 568 | 531 | 506 | |||||||||||||
Net income after dividends on preferred and preference stock | 119 | 325 | 230 | 174 | 102 | 351 | 213 | 156 | 848 | 822 | 785 | |||||
GULF POWER CO | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 372 | 437 | 357 | 350 | 349 | 436 | 365 | 335 | 1,516 | 1,485 | 1,483 | |||||
Operating income (loss) | 53 | 115 | 75 | 46 | 54 | 90 | 74 | 65 | 289 | 283 | 290 | |||||
Income taxes | 90 | 91 | 92 | |||||||||||||
Net income after dividends on preferred and preference stock | 19 | 63 | 35 | 18 | 23 | 45 | 34 | 29 | 135 | 131 | 148 | |||||
After tax charge to income | 0 | |||||||||||||||
MISSISSIPPI POWER CO | ||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | 372 | |||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 271 | 341 | 303 | 272 | 277 | 352 | 277 | 257 | 1,187 | 1,163 | 1,138 | |||||
Operating income (loss) | (177) | 51 | (2,954) | (62) | (166) | 9 | (28) | (10) | (3,142) | (195) | (173) | |||||
Income taxes | (532) | (104) | (72) | |||||||||||||
Net income after dividends on preferred and preference stock | (556) | 40 | (2,054) | (20) | (89) | 26 | 2 | 11 | (2,590) | (50) | (8) | |||||
SOUTHERN POWER CO | ||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||
Tax Cuts And Jobs Act Of 2017, incomplete accounting, provisional income tax expense (benefit) | (743) | |||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 478 | 618 | 529 | 450 | 389 | 500 | 373 | 315 | 2,075 | 1,577 | 1,390 | |||||
Operating income (loss) | 32 | 159 | 112 | 65 | 28 | 134 | 81 | 47 | 368 | 290 | 326 | |||||
Income taxes | (810) | (39) | (38) | (52) | (29) | (102) | (41) | (23) | (939) | (195) | 21 | |||||
Net income after dividends on preferred and preference stock | 795 | 124 | 82 | 70 | 23 | 176 | 89 | 50 | ||||||||
SOUTHERN Co GAS | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 1,079 | 565 | 716 | 1,560 | 1,109 | 543 | $ 1,652 | 3,920 | ||||||||
Operating income (loss) | 110 | 68 | 96 | 391 | 185 | 12 | 197 | 665 | ||||||||
Income taxes | 76 | 367 | ||||||||||||||
EBIT | 129 | 118 | 128 | 435 | 221 | 50 | ||||||||||
Net income after dividends on preferred and preference stock | (60) | 15 | 49 | 239 | 110 | 4 | $ 114 | 243 | ||||||||
Kemper IGCC | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Pre-Tax charge to income | 208 | 34 | 3,000 | 108 | 206 | 88 | 81 | 53 | ||||||||
After tax charge to income | 185 | 21 | 2,100 | 67 | 127 | 54 | 50 | 33 | $ 2,400 | $ 264 | 226 | |||||
Kemper IGCC | MISSISSIPPI POWER CO | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Pre-Tax charge to income | $ 2,800 | 208 | 34 | 3,000 | 108 | 206 | 88 | 81 | 53 | $ 242 | $ 3,070 | |||||
After tax charge to income | $ 2,000 | $ 185 | $ 21 | $ 2,100 | $ 67 | $ 127 | $ 54 | 50 | 33 | $ 206 | $ 1,890 | |||||
Predecessor | SOUTHERN Co GAS | ||||||||||||||||
Summarized quarterly financial information | ||||||||||||||||
Operating revenues | 571 | 1,334 | $ 1,905 | 3,941 | ||||||||||||
Operating income (loss) | (27) | 348 | 321 | 746 | ||||||||||||
Income taxes | 87 | 213 | ||||||||||||||
EBIT | (23) | 351 | 328 | 761 | ||||||||||||
Net income after dividends on preferred and preference stock | $ (51) | $ 182 | $ 131 | $ 353 |
Valuation and Qualifying Acc144
Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | $ 13,341 | $ 43,429 | $ 13,341 | $ 18,253 | |
Charged to Income | 55,770 | 39,959 | 31,074 | ||
Charged to Other Accounts | (248) | (1,257) | 0 | ||
Acquisitions | 30 | 40,629 | 0 | ||
Deductions (Note) | 54,605 | 49,243 | 35,986 | ||
Balance at End of Period | $ 43,429 | 44,376 | 43,429 | 13,341 | |
SOUTHERN Co GAS | Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 37,663 | 27,316 | |||
Charged to Income | 9,500 | 28,022 | |||
Charged to Other Accounts | (1,257) | (248) | |||
Deductions (Note) | 18,590 | 27,286 | |||
Balance at End of Period | 27,316 | 37,663 | 27,804 | 27,316 | |
SOUTHERN Co GAS | Income tax valuation | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 19,182 | 19,182 | |||
Charged to Income | 0 | 0 | |||
Charged to Other Accounts | 0 | 0 | |||
Deductions (Note) | 0 | 7,910 | |||
Balance at End of Period | 19,182 | 19,182 | 11,272 | 19,182 | |
MISSISSIPPI POWER CO | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Retail rate recovery | 371,000 | ||||
MISSISSIPPI POWER CO | Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 287 | 494 | 287 | 825 | |
Charged to Income | 1,377 | 1,295 | (1,994) | ||
Charged to Other Accounts | 0 | 0 | 0 | ||
Deductions (Note) | 1,279 | 1,088 | (1,456) | ||
Balance at End of Period | 494 | 592 | 494 | 287 | |
ALABAMA POWER CO | Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 9,597 | 10,487 | 9,597 | 9,143 | |
Charged to Income | 9,367 | 11,310 | 13,500 | ||
Charged to Other Accounts | 0 | 0 | 0 | ||
Deductions (Note) | 11,075 | 10,420 | 13,046 | ||
Balance at End of Period | 10,487 | 8,779 | 10,487 | 9,597 | |
GEORGIA POWER CO | Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 2,147 | 2,836 | 2,147 | 6,076 | |
Charged to Income | 11,250 | 14,476 | 16,862 | ||
Charged to Other Accounts | 0 | 0 | 0 | ||
Deductions (Note) | 11,474 | 13,787 | 20,791 | ||
Balance at End of Period | 2,836 | 2,612 | 2,836 | 2,147 | |
GULF POWER CO | Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 775 | 732 | 775 | 2,087 | |
Charged to Income | 2,859 | 2,946 | 2,041 | ||
Charged to Other Accounts | 0 | 0 | 0 | ||
Deductions (Note) | 2,846 | 2,989 | 3,353 | ||
Balance at End of Period | 732 | $ 745 | 732 | 775 | |
Predecessor | SOUTHERN Co GAS | Provision for uncollectible accounts | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | 37,663 | 29,142 | 29,142 | 35,069 | |
Charged to Income | 15,976 | 27,050 | |||
Charged to Other Accounts | 1,608 | 3,017 | |||
Deductions (Note) | 9,063 | 35,994 | |||
Balance at End of Period | 37,663 | 29,142 | |||
Predecessor | SOUTHERN Co GAS | Income tax valuation | |||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||
Balance at Beginning of Period | $ 19,182 | 19,182 | $ 19,182 | 19,637 | |
Charged to Income | 0 | 0 | |||
Charged to Other Accounts | 0 | 0 | |||
Deductions (Note) | 0 | 455 | |||
Balance at End of Period | $ 19,182 | $ 19,182 |
Uncategorized Items - so-201712
Label | Element | Value |
Southern Company Gas [Member] | ||
Proceeds from (Payments for) Other Financing Activities | us-gaap_ProceedsFromPaymentsForOtherFinancingActivities | $ (8,000,000) |
Payment for Pension and Other Postretirement Benefits | us-gaap_PensionAndOtherPostretirementBenefitContributions | 125,000,000 |
Payments for (Proceeds from) Removal Costs | us-gaap_PaymentsForProceedsFromRemovalCosts | 40,000,000 |
Increase (Decrease) in Other Current Liabilities | us-gaap_IncreaseDecreaseInOtherCurrentLiabilities | 24,000,000 |
Increase (Decrease) in Other Operating Assets | us-gaap_IncreaseDecreaseInOtherOperatingAssets | 31,000,000 |
Change in Construction Payables | so_ChangeInConstructionPayables | 22,000,000 |
Increase (Decrease) in Accrued Salaries | us-gaap_IncreaseDecreaseInAccruedSalaries | (13,000,000) |
Pension and Other Postretirement Benefits Cost (Reversal of Cost) | us-gaap_PensionAndOtherPostretirementBenefitExpense | 6,000,000 |
Other Noncash Income (Expense) | us-gaap_OtherNoncashIncomeExpense | 78,000,000 |
Net Cash Provided by (Used in) Investing Activities | us-gaap_NetCashProvidedByUsedInInvestingActivities | (2,067,000,000) |
Deferred Income Tax Expense (Benefit) | us-gaap_DeferredIncomeTaxExpenseBenefit | 92,000,000 |
Net Cash Provided by (Used in) Financing Activities | us-gaap_NetCashProvidedByUsedInFinancingActivities | 2,399,000,000 |
Cash and Cash Equivalents, Period Increase (Decrease) | us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease | 4,000,000 |
Proceeds from Equity Method Investment, Distribution, Return of Capital | us-gaap_ProceedsFromEquityMethodInvestmentDividendsOrDistributionsReturnOfCapital | 5,000,000 |
Goodwill, Impairment Loss | us-gaap_GoodwillImpairmentLoss | 0 |
Stock or Unit Option Plan Expense | us-gaap_StockOptionPlanExpense | 20,000,000 |
Proceeds from Issuance of Senior Long-term Debt | us-gaap_ProceedsFromIssuanceOfSeniorLongTermDebt | 900,000,000 |
Proceeds from (Payments to) Noncontrolling Interests | us-gaap_ProceedsFromPaymentsToMinorityShareholders | (160,000,000) |
Payments for (Proceeds from) Other Investing Activities | us-gaap_PaymentsForProceedsFromOtherInvestingActivities | (4,000,000) |
Proceeds from (Repayments of) Short-term Debt | us-gaap_ProceedsFromRepaymentsOfShortTermDebt | 1,143,000,000 |
Increase Decrease in Accrued Taxes | so_IncreaseDecreaseInAccruedTaxes | 8,000,000 |
Repayments of Medium-term Notes | us-gaap_RepaymentsOfMediumTermNotes | 0 |
Increase (Decrease) in Prepaid Taxes | us-gaap_IncreaseDecreaseInPrepaidTaxes | 23,000,000 |
Payments to Acquire Property, Plant, and Equipment | us-gaap_PaymentsToAcquirePropertyPlantAndEquipment | 614,000,000 |
Increase (Decrease) in Accounts Payable | us-gaap_IncreaseDecreaseInAccountsPayable | 194,000,000 |
Increase (Decrease) in Receivables | us-gaap_IncreaseDecreaseInReceivables | 490,000,000 |
Hedge Settlements | so_HedgeSettlements | 35,000,000 |
Net Cash Provided by (Used in) Operating Activities | us-gaap_NetCashProvidedByUsedInOperatingActivities | (328,000,000) |
Payments of Ordinary Dividends, Common Stock | us-gaap_PaymentsOfDividendsCommonStock | 126,000,000 |
Increase (Decrease) in Energy Related Inventory, Natural Gas in Storage | so_IncreaseDecreaseinEnergyRelatedInventoryNaturalGasinStorage | 226,000,000 |
Proceeds from Issuance of First Mortgage Bond | us-gaap_ProceedsFromIssuanceOfFirstMortgageBond | 0 |
Southern Company Gas [Member] | Predecessor [Member] | ||
Proceeds from (Payments for) Other Financing Activities | us-gaap_ProceedsFromPaymentsForOtherFinancingActivities | 10,000,000 |
Payment for Pension and Other Postretirement Benefits | us-gaap_PensionAndOtherPostretirementBenefitContributions | 0 |
Payments for (Proceeds from) Removal Costs | us-gaap_PaymentsForProceedsFromRemovalCosts | 32,000,000 |
Increase (Decrease) in Other Current Liabilities | us-gaap_IncreaseDecreaseInOtherCurrentLiabilities | (30,000,000) |
Increase (Decrease) in Other Operating Assets | us-gaap_IncreaseDecreaseInOtherOperatingAssets | (37,000,000) |
Change in Construction Payables | so_ChangeInConstructionPayables | (7,000,000) |
Increase (Decrease) in Accrued Salaries | us-gaap_IncreaseDecreaseInAccruedSalaries | (21,000,000) |
Pension and Other Postretirement Benefits Cost (Reversal of Cost) | us-gaap_PensionAndOtherPostretirementBenefitExpense | 5,000,000 |
Other Noncash Income (Expense) | us-gaap_OtherNoncashIncomeExpense | 82,000,000 |
Net Cash Provided by (Used in) Investing Activities | us-gaap_NetCashProvidedByUsedInInvestingActivities | (559,000,000) |
Proceeds from Contributions from Parent | us-gaap_ProceedsFromContributionsFromParent | 0 |
Deferred Income Tax Expense (Benefit) | us-gaap_DeferredIncomeTaxExpenseBenefit | 8,000,000 |
Net Cash Provided by (Used in) Financing Activities | us-gaap_NetCashProvidedByUsedInFinancingActivities | (558,000,000) |
Repayments of Senior Debt | us-gaap_RepaymentsOfSeniorDebt | 0 |
Cash and Cash Equivalents, Period Increase (Decrease) | us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease | (4,000,000) |
Proceeds from Equity Method Investment, Distribution, Return of Capital | us-gaap_ProceedsFromEquityMethodInvestmentDividendsOrDistributionsReturnOfCapital | 3,000,000 |
Repayments of First Mortgage Bond | us-gaap_RepaymentsOfFirstMortgageBond | 125,000,000 |
Goodwill, Impairment Loss | us-gaap_GoodwillImpairmentLoss | 0 |
Stock or Unit Option Plan Expense | us-gaap_StockOptionPlanExpense | 20,000,000 |
Proceeds from Issuance of Senior Long-term Debt | us-gaap_ProceedsFromIssuanceOfSeniorLongTermDebt | 350,000,000 |
Proceeds from (Payments to) Noncontrolling Interests | us-gaap_ProceedsFromPaymentsToMinorityShareholders | 0 |
Payments for (Proceeds from) Other Investing Activities | us-gaap_PaymentsForProceedsFromOtherInvestingActivities | 0 |
Proceeds from (Repayments of) Short-term Debt | us-gaap_ProceedsFromRepaymentsOfShortTermDebt | (896,000,000) |
Increase Decrease in Accrued Taxes | so_IncreaseDecreaseInAccruedTaxes | 41,000,000 |
Repayments of Medium-term Notes | us-gaap_RepaymentsOfMediumTermNotes | 0 |
Increase (Decrease) in Prepaid Taxes | us-gaap_IncreaseDecreaseInPrepaidTaxes | (151,000,000) |
Payments to Acquire Property, Plant, and Equipment | us-gaap_PaymentsToAcquirePropertyPlantAndEquipment | 509,000,000 |
Increase (Decrease) in Accounts Payable | us-gaap_IncreaseDecreaseInAccountsPayable | 43,000,000 |
Increase (Decrease) in Receivables | us-gaap_IncreaseDecreaseInReceivables | (181,000,000) |
Hedge Settlements | so_HedgeSettlements | 26,000,000 |
Net Cash Provided by (Used in) Operating Activities | us-gaap_NetCashProvidedByUsedInOperatingActivities | 1,113,000,000 |
Payments of Ordinary Dividends, Common Stock | us-gaap_PaymentsOfDividendsCommonStock | 128,000,000 |
Increase (Decrease) in Energy Related Inventory, Natural Gas in Storage | so_IncreaseDecreaseinEnergyRelatedInventoryNaturalGasinStorage | (273,000,000) |
Proceeds from Issuance of First Mortgage Bond | us-gaap_ProceedsFromIssuanceOfFirstMortgageBond | $ 250,000,000 |