Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2015 | Jan. 31, 2016 | Jun. 30, 2015 | |
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, 2015 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,015 | ||
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 | $ 38.1 | ||
Entity Common Stock, Shares Outstanding | 912,846,995 | ||
Alabama Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | ALABAMA POWER CO | ||
Entity Central Index Key | 3,153 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 30,537,500 | ||
Georgia Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | GEORGIA POWER CO | ||
Entity Central Index Key | 41,091 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 9,261,500 | ||
Gulf Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | GULF POWER CO | ||
Entity Central Index Key | 44,545 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 5,642,717 | ||
Mississippi Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | MISSISSIPPI POWER CO | ||
Entity Central Index Key | 66,904 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 1,121,000 | ||
Southern Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | SOUTHERN POWER CO | ||
Entity Central Index Key | 1,160,661 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 1,000 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Revenues: | |||
Retail revenues | $ 14,987 | $ 15,550 | $ 14,541 |
Wholesale revenues | 1,798 | 2,184 | 1,855 |
Other electric revenues | 657 | 672 | 639 |
Other revenues | 47 | 61 | 52 |
Total operating revenues | 17,489 | 18,467 | 17,087 |
Operating Expenses: | |||
Fuel | 4,750 | 6,005 | 5,510 |
Purchased power | 645 | 672 | 461 |
Other operations and maintenance | 4,416 | 4,354 | 3,846 |
Depreciation and amortization | 2,034 | 1,945 | 1,901 |
Taxes other than income taxes | 997 | 981 | 934 |
Estimated loss on Kemper IGCC | 365 | 868 | 1,180 |
Total operating expenses | 13,207 | 14,825 | 13,832 |
Operating Income | 4,282 | 3,642 | 3,255 |
Other Income and (Expense): | |||
Allowance for equity funds used during construction | 226 | 245 | 190 |
Interest income | 23 | 19 | 19 |
Interest expense, net of amounts capitalized | (840) | (835) | (824) |
Other income (expense), net | (62) | (63) | (81) |
Total other income and (expense) | (653) | (634) | (696) |
Earnings Before Income Taxes | 3,629 | 3,008 | 2,559 |
Income taxes | 1,194 | 977 | 849 |
Net Income (loss) | 2,435 | 2,031 | 1,710 |
Dividends on Preferred and Preference Stock | 54 | 68 | 66 |
Net income attributable to noncontrolling interests | 14 | 0 | 0 |
Net Income After Dividends on Preferred and Preference Stock | $ 2,367 | $ 1,963 | $ 1,644 |
Earnings per share (EPS) — | |||
Basic EPS (in dollars per share) | $ 2.60 | $ 2.19 | $ 1.88 |
Diluted EPS (in dollars per share) | $ 2.59 | $ 2.18 | $ 1.87 |
Average number of shares of common stock outstanding — (in millions) | |||
Basic shares | 910 | 897 | 877 |
Diluted shares | 914 | 901 | 881 |
Alabama Power [Member] | |||
Operating Revenues: | |||
Retail revenues | $ 5,234 | $ 5,249 | $ 4,952 |
Wholesale revenues, non-affiliates | 241 | 281 | 248 |
Wholesale revenues, affiliates | 84 | 189 | 212 |
Other revenues | 209 | 223 | 206 |
Total operating revenues | 5,768 | 5,942 | 5,618 |
Operating Expenses: | |||
Fuel | 1,342 | 1,605 | 1,631 |
Purchased power, non-affiliates | 171 | 185 | 100 |
Purchased power, affiliates | 180 | 200 | 129 |
Other operations and maintenance | 1,501 | 1,468 | 1,289 |
Depreciation and amortization | 643 | 603 | 645 |
Taxes other than income taxes | 368 | 356 | 348 |
Total operating expenses | 4,205 | 4,417 | 4,142 |
Operating Income | 1,563 | 1,525 | 1,476 |
Other Income and (Expense): | |||
Allowance for equity funds used during construction | 60 | 49 | 32 |
Interest income | 15 | 15 | 16 |
Interest expense, net of amounts capitalized | (274) | (255) | (259) |
Other income (expense), net | (47) | (22) | (36) |
Total other income and (expense) | (246) | (213) | (247) |
Earnings Before Income Taxes | 1,317 | 1,312 | 1,229 |
Income taxes | 506 | 512 | 478 |
Net Income (loss) | 811 | 800 | 751 |
Dividends on Preferred and Preference Stock | 26 | 39 | 39 |
Net Income After Dividends on Preferred and Preference Stock | 785 | 761 | 712 |
Georgia Power [Member] | |||
Operating Revenues: | |||
Retail revenues | 7,727 | 8,240 | 7,620 |
Wholesale revenues, non-affiliates | 215 | 335 | 281 |
Wholesale revenues, affiliates | 20 | 42 | 20 |
Other revenues | 364 | 371 | 353 |
Total operating revenues | 8,326 | 8,988 | 8,274 |
Operating Expenses: | |||
Fuel | 2,033 | 2,547 | 2,307 |
Purchased power, non-affiliates | 289 | 287 | 224 |
Purchased power, affiliates | 575 | 701 | 660 |
Other operations and maintenance | 1,844 | 1,902 | 1,654 |
Depreciation and amortization | 846 | 846 | 807 |
Taxes other than income taxes | 391 | 409 | 382 |
Total operating expenses | 5,978 | 6,692 | 6,034 |
Operating Income | 2,348 | 2,296 | 2,240 |
Other Income and (Expense): | |||
Allowance for equity funds used during construction | 40 | 45 | 30 |
Interest expense, net of amounts capitalized | (363) | (348) | (361) |
Other income (expense), net | 61 | 23 | 35 |
Total other income and (expense) | (302) | (325) | (326) |
Earnings Before Income Taxes | 2,046 | 1,971 | 1,914 |
Income taxes | 769 | 729 | 723 |
Net Income (loss) | 1,277 | 1,242 | 1,191 |
Dividends on Preferred and Preference Stock | 17 | 17 | 17 |
Net Income After Dividends on Preferred and Preference Stock | 1,260 | 1,225 | 1,174 |
Gulf Power [Member] | |||
Operating Revenues: | |||
Retail revenues | 1,249 | 1,267 | 1,170 |
Wholesale revenues, non-affiliates | 107 | 129 | 109 |
Wholesale revenues, affiliates | 58 | 130 | 100 |
Other revenues | 69 | 64 | 61 |
Total operating revenues | 1,483 | 1,590 | 1,440 |
Operating Expenses: | |||
Fuel | 445 | 605 | 533 |
Purchased power, non-affiliates | 100 | 82 | 52 |
Purchased power, affiliates | 35 | 25 | 33 |
Other operations and maintenance | 354 | 341 | 310 |
Depreciation and amortization | 141 | 145 | 149 |
Taxes other than income taxes | 118 | 111 | 98 |
Total operating expenses | 1,193 | 1,309 | 1,175 |
Operating Income | 290 | 281 | 265 |
Other Income and (Expense): | |||
Allowance for equity funds used during construction | 13 | 12 | 6 |
Interest expense, net of amounts capitalized | (49) | (53) | (56) |
Other income (expense), net | (5) | (3) | (3) |
Total other income and (expense) | (41) | (44) | (53) |
Earnings Before Income Taxes | 249 | 237 | 212 |
Income taxes | 92 | 88 | 80 |
Net Income (loss) | 157 | 149 | 132 |
Dividends on Preferred and Preference Stock | 9 | 9 | 8 |
Net Income After Dividends on Preferred and Preference Stock | 148 | 140 | 124 |
Mississippi Power [Member] | |||
Operating Revenues: | |||
Retail revenues | 776 | 795 | 799 |
Wholesale revenues, non-affiliates | 270 | 323 | 294 |
Wholesale revenues, affiliates | 76 | 107 | 35 |
Other revenues | 16 | 18 | 17 |
Total operating revenues | 1,138 | 1,243 | 1,145 |
Operating Expenses: | |||
Fuel | 443 | 574 | 491 |
Purchased power, non-affiliates | 5 | 18 | 6 |
Purchased power, affiliates | 7 | 25 | 43 |
Other operations and maintenance | 274 | 271 | 253 |
Depreciation and amortization | 123 | 97 | 91 |
Taxes other than income taxes | 94 | 79 | 81 |
Estimated loss on Kemper IGCC | 365 | 868 | 1,102 |
Total operating expenses | 1,311 | 1,932 | 2,067 |
Operating Income | (173) | (689) | (922) |
Other Income and (Expense): | |||
Allowance for equity funds used during construction | 110 | 136 | 122 |
Interest expense, net of amounts capitalized | (7) | (45) | (36) |
Other income (expense), net | (8) | (14) | (7) |
Total other income and (expense) | 95 | 77 | 79 |
Earnings Before Income Taxes | (78) | (612) | (843) |
Income taxes | (72) | (285) | (368) |
Net Income (loss) | (6) | (327) | (475) |
Dividends on Preferred and Preference Stock | 2 | 2 | 2 |
Net Income After Dividends on Preferred and Preference Stock | (8) | (329) | (477) |
Southern Power [Member] | |||
Operating Revenues: | |||
Wholesale revenues, non-affiliates | 964 | 1,116 | 923 |
Wholesale revenues, affiliates | 417 | 383 | 346 |
Other revenues | 9 | 2 | 6 |
Total operating revenues | 1,390 | 1,501 | 1,275 |
Operating Expenses: | |||
Fuel | 441 | 596 | 474 |
Purchased power, non-affiliates | 72 | 105 | 76 |
Purchased power, affiliates | 21 | 66 | 30 |
Other operations and maintenance | 260 | 237 | 209 |
Depreciation and amortization | 248 | 220 | 175 |
Taxes other than income taxes | 22 | 22 | 21 |
Total operating expenses | 1,064 | 1,246 | 985 |
Operating Income | 326 | 255 | 290 |
Other Income and (Expense): | |||
Interest expense, net of amounts capitalized | (77) | (89) | (74) |
Other income (expense), net | 1 | 6 | (4) |
Total other income and (expense) | (76) | (83) | (78) |
Earnings Before Income Taxes | 250 | 172 | 212 |
Income taxes | 21 | (3) | 46 |
Net Income (loss) | 229 | 175 | 166 |
Net income attributable to noncontrolling interests | 14 | 3 | 0 |
Net Income (Loss) Attributable to Parent | $ 215 | $ 172 | $ 166 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net Income (Loss) | $ 2,435 | $ 2,031 | $ 1,710 |
Qualifying hedges: | |||
Changes in fair value, net of tax | (13) | (10) | 0 |
Reclassification adjustment for amounts included in net income, net of tax | 6 | 5 | 9 |
Marketable securities: | |||
Change in fair value, net of tax | 0 | 0 | (3) |
Pension and other postretirement benefit plans: | |||
Benefit plan net gain (loss),net of tax | (2) | (51) | 36 |
Reclassification adjustment for amounts included in net income, net of tax | 7 | 3 | 6 |
Total other comprehensive income (loss) | (2) | (53) | 48 |
Dividends on preferred and preference stock of subsidiaries | 54 | 68 | 66 |
Comprehensive income attributable to noncontrolling interests | 14 | 0 | 0 |
Comprehensive Income | 2,365 | 1,910 | 1,692 |
Alabama Power [Member] | |||
Net Income (Loss) | 811 | 800 | 751 |
Qualifying hedges: | |||
Changes in fair value, net of tax | (5) | (5) | 0 |
Reclassification adjustment for amounts included in net income, net of tax | 2 | 2 | 1 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | (3) | (3) | 1 |
Dividends on preferred and preference stock of subsidiaries | 26 | 39 | 39 |
Comprehensive Income | 808 | 797 | 752 |
Georgia Power [Member] | |||
Net Income (Loss) | 1,277 | 1,242 | 1,191 |
Qualifying hedges: | |||
Changes in fair value, net of tax | (9) | (5) | 0 |
Reclassification adjustment for amounts included in net income, net of tax | 2 | 2 | 2 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | (7) | (3) | 2 |
Dividends on preferred and preference stock of subsidiaries | 17 | 17 | 17 |
Comprehensive Income | 1,270 | 1,239 | 1,193 |
Gulf Power [Member] | |||
Net Income (Loss) | 157 | 149 | 132 |
Qualifying hedges: | |||
Changes in fair value, net of tax | 1 | 0 | 0 |
Reclassification adjustment for amounts included in net income, net of tax | 0 | 0 | 1 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | 1 | 0 | 1 |
Dividends on preferred and preference stock of subsidiaries | 9 | 9 | 8 |
Comprehensive Income | 158 | 149 | 133 |
Mississippi Power [Member] | |||
Net Income (Loss) | (6) | (327) | (475) |
Qualifying hedges: | |||
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) | 1 | 1 | 1 |
Dividends on preferred and preference stock of subsidiaries | 2 | 2 | 2 |
Comprehensive Income | (5) | (326) | (474) |
Southern Power [Member] | |||
Net Income (Loss) | 229 | 175 | 166 |
Qualifying hedges: | |||
Reclassification adjustment for amounts included in net income, net of tax | 1 | 0 | 4 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | 1 | 0 | 4 |
Comprehensive income attributable to noncontrolling interests | 14 | 3 | 0 |
Comprehensive Income | $ 216 | $ 172 | $ 170 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Changes in fair value of qualifying hedges, tax | $ (8) | $ (6) | $ 0 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 4 | 3 | 5 |
Change in fair value of marketable securities, tax | 0 | 0 | (2) |
Benefit plan net gain (loss), tax | (1) | (32) | 22 |
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax | 4 | 2 | 4 |
Alabama Power [Member] | |||
Changes in fair value of qualifying hedges, tax | (3) | (3) | 0 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 1 | 1 | 1 |
Georgia Power [Member] | |||
Changes in fair value of qualifying hedges, tax | (6) | (3) | 0 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 1 | 1 | 1 |
Gulf Power [Member] | |||
Changes in fair value of qualifying hedges, tax | 0 | 0 | 0 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 0 | 0 | 0 |
Mississippi Power [Member] | |||
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 1 | 1 | 1 |
Southern Power [Member] | |||
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | $ 0 | $ 0 | $ 2 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Activities: | |||
Net Income (Loss) | $ 2,435 | $ 2,031 | $ 1,710 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 2,395 | 2,293 | 2,298 |
Deferred income taxes | 1,404 | 709 | 496 |
Investment tax credits | (48) | 35 | 302 |
Allowance for equity funds used during construction | (226) | (245) | (190) |
Pension, postretirement, and other employee benefits | 76 | (515) | 131 |
Stock based compensation expense | 99 | 63 | 59 |
Estimated loss on Kemper IGCC | 365 | 868 | 1,180 |
Income taxes receivable, non-current | (413) | 0 | 0 |
Amortization of Deferred Investment Tax Credits | (21) | (22) | (16) |
Other, net | (39) | (39) | (41) |
Changes in certain current assets and liabilities -- | |||
-Receivables | 243 | (352) | (153) |
-Fossil fuel stock | 61 | 408 | 481 |
-Materials and supplies | (44) | (67) | 36 |
-Other current assets | (108) | (57) | (11) |
-Accounts payable | (353) | 267 | 72 |
-Accrued taxes | 352 | (105) | (85) |
-Accrued compensation | (41) | 255 | (138) |
-Retail fuel cost over-recovery—short-term | 289 | (23) | (66) |
-Mirror CWIP | (271) | 180 | 0 |
-Other current liabilities | 98 | 109 | 16 |
Net cash provided from operating activities | 6,274 | 5,815 | 6,097 |
Investing Activities: | |||
Plant acquisitions | (1,719) | (731) | (132) |
Property additions | (5,674) | (5,246) | (5,331) |
Investment in restricted cash | (160) | (11) | (149) |
Distribution of restricted cash | 154 | 57 | 96 |
Nuclear decommissioning trust fund purchases | (1,424) | (916) | (986) |
Nuclear decommissioning trust fund sales | 1,418 | 914 | 984 |
Cost of removal, net of salvage | (167) | (170) | (131) |
Change in construction payables | 402 | (107) | (126) |
Prepaid long-term service agreement | (197) | (181) | (91) |
Other investing activities | 87 | (17) | 124 |
Net cash used for investing activities | (7,280) | (6,408) | (5,742) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | 73 | (676) | 662 |
Proceeds -- | |||
Long-term debt issuances | 7,029 | 3,169 | 2,938 |
Common stock issuances | 256 | 806 | 695 |
Interest-bearing refundable deposit related to asset sale | 0 | 125 | 0 |
Short-term borrowings | 755 | 0 | 0 |
Redemptions and repurchases -- | |||
Long-term debt | (3,604) | (816) | (2,830) |
Common stock repurchased | (115) | (5) | (20) |
Interest-bearing refundable deposits | (275) | 0 | 0 |
Preferred and preference stock | (412) | 0 | 0 |
Short-term borrowings | (255) | 0 | 0 |
Capital contributions from noncontrolling interests | 341 | 8 | 17 |
Payment of common stock dividends | (1,959) | (1,866) | (1,762) |
Payment of dividends on preferred and preference stock of subsidiaries | (59) | (68) | (66) |
Other financing activities | (75) | (33) | 42 |
Net cash provided from (used for) financing activities | 1,700 | 644 | (324) |
Net Change in Cash and Cash Equivalents | 694 | 51 | 31 |
Cash and Cash Equivalents at Beginning of Year | 710 | 659 | 628 |
Cash and Cash Equivalents at End of Year | 1,404 | 710 | 659 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 809 | 732 | 759 |
Income taxes (net of refunds) | (9) | 272 | 139 |
Alabama Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 811 | 800 | 751 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 780 | 724 | 816 |
Deferred income taxes | 388 | 270 | 198 |
Allowance for equity funds used during construction | (60) | (49) | (32) |
Pension, postretirement, and other employee benefits | 20 | (61) | 9 |
Stock based compensation expense | 15 | 11 | 10 |
Amortization of Deferred Investment Tax Credits | (8) | (8) | (8) |
Other, net | (20) | 17 | (38) |
Changes in certain current assets and liabilities -- | |||
-Receivables | (160) | (58) | 2 |
-Fossil fuel stock | 28 | 61 | 146 |
-Materials and supplies | 15 | (17) | 19 |
-Other current assets | (3) | (11) | 5 |
-Accounts payable | 3 | 157 | 35 |
-Accrued taxes | 138 | (199) | (23) |
-Accrued compensation | (16) | 50 | (23) |
-Retail fuel cost over-recovery—short-term | 191 | 5 | 42 |
-Other current liabilities | 12 | 9 | (3) |
Net cash provided from operating activities | 2,142 | 1,709 | 1,914 |
Investing Activities: | |||
Property additions | (1,367) | (1,457) | (1,107) |
Nuclear decommissioning trust fund purchases | (439) | (245) | (280) |
Nuclear decommissioning trust fund sales | 438 | 244 | 279 |
Cost of removal, net of salvage | (71) | (77) | (47) |
Change in construction payables | (15) | (10) | (13) |
Other investing activities | (34) | (22) | 26 |
Net cash used for investing activities | (1,488) | (1,567) | (1,142) |
Proceeds -- | |||
Capital contributions from parent company | 22 | 28 | 24 |
Pollution control revenue bonds issuances and remarketings | 80 | 254 | 0 |
Senior note issuances | 975 | 400 | 300 |
Redemptions and repurchases -- | |||
Preferred and preference stock | (412) | 0 | 0 |
Pollution control revenue bonds | (134) | (254) | 0 |
Senior notes | (650) | 0 | (250) |
Payment of preferred and preference stock dividends | (31) | (39) | (39) |
Payment of common stock dividends | (571) | (550) | (644) |
Other financing activities | (12) | (3) | (5) |
Net cash provided from (used for) financing activities | (733) | (164) | (614) |
Net Change in Cash and Cash Equivalents | (79) | (22) | 158 |
Cash and Cash Equivalents at Beginning of Year | 273 | 295 | 137 |
Cash and Cash Equivalents at End of Year | 194 | 273 | 295 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 250 | 231 | 243 |
Income taxes (net of refunds) | 121 | 436 | 296 |
Noncash transactions - | |||
Accrued property additions at year-end | 121 | 8 | 18 |
Georgia Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 1,277 | 1,242 | 1,191 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 1,029 | 1,019 | 979 |
Deferred income taxes | 173 | 352 | 476 |
Allowance for equity funds used during construction | (40) | (45) | (30) |
Retail fuel cost-recovery - long-term | 106 | (44) | (123) |
Pension, postretirement, and other employee benefits | 40 | 19 | 66 |
Pension and postretirement funding | (7) | (156) | (8) |
Amortization of Deferred Investment Tax Credits | (10) | (10) | (5) |
Other, net | (59) | 39 | 38 |
Changes in certain current assets and liabilities -- | |||
-Receivables | 187 | (248) | (58) |
-Fossil fuel stock | 37 | 303 | 250 |
-Prepaid income taxes | 89 | (216) | (17) |
-Other current assets | (62) | (37) | 40 |
-Accounts payable | (259) | 16 | 67 |
-Accrued taxes | 25 | 17 | (14) |
-Accrued compensation | (17) | 62 | (37) |
-Retail fuel cost over-recovery—short-term | 10 | (14) | (49) |
-Other current liabilities | (12) | 54 | (5) |
Net cash provided from operating activities | 2,517 | 2,363 | 2,766 |
Investing Activities: | |||
Property additions | (2,091) | (2,023) | (1,743) |
Investment in restricted cash from pollution control bonds | 0 | 0 | (89) |
Distribution of restricted cash from pollution control revenue bonds | 0 | 0 | 89 |
Nuclear decommissioning trust fund purchases | (985) | (671) | (706) |
Nuclear decommissioning trust fund sales | 980 | 669 | 705 |
Cost of removal, net of salvage | (71) | (65) | (59) |
Change in construction payables, net of joint owner portion | 217 | (54) | (67) |
Prepaid long-term service agreement | (66) | (70) | (18) |
Sale of property | 70 | 7 | 7 |
Other investing activities | 2 | 1 | (9) |
Net cash used for investing activities | (1,944) | (2,206) | (1,890) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | 2 | (891) | 1,047 |
Proceeds -- | |||
Capital contributions from parent company | 62 | 549 | 37 |
Pollution control revenue bonds issuances and remarketings | 409 | 40 | 194 |
Senior note issuances | 500 | 0 | 850 |
Federal Financing Bank Loan | 1,000 | 1,200 | 0 |
Short-term borrowings | 250 | 0 | 0 |
Redemptions and repurchases -- | |||
Pollution control revenue bonds | (268) | (37) | (298) |
Senior notes | (1,175) | 0 | (1,775) |
Short-term borrowings | (250) | 0 | 0 |
Payment of preferred and preference stock dividends | (17) | (17) | (17) |
Payment of common stock dividends | (1,034) | (954) | (907) |
FFB loan issuance costs | 0 | (49) | (5) |
Other financing activities | (9) | (4) | (17) |
Net cash provided from (used for) financing activities | (530) | (163) | (891) |
Net Change in Cash and Cash Equivalents | 43 | (6) | (15) |
Cash and Cash Equivalents at Beginning of Year | 24 | 30 | 45 |
Cash and Cash Equivalents at End of Year | 67 | 24 | 30 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 353 | 319 | 344 |
Income taxes (net of refunds) | 506 | 507 | 298 |
Noncash transactions - | |||
Accrued property additions at year-end | 387 | 154 | 208 |
Capital lease obligation | 149 | 0 | 0 |
Gulf Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 157 | 149 | 132 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 152 | 153 | 156 |
Deferred income taxes | 90 | 65 | 77 |
Allowance for equity funds used during construction | (13) | (12) | (6) |
Pension, postretirement, and other employee benefits | 10 | (23) | 11 |
Amortization of Deferred Investment Tax Credits | (1) | 0 | (1.4) |
Other, net | 7 | 2 | 9 |
Changes in certain current assets and liabilities -- | |||
-Receivables | 33 | (17) | (49) |
-Fossil fuel stock | (6) | 34 | 19 |
-Prepaid income taxes | 32 | (19) | 16 |
-Other current assets | (2) | (2) | (1) |
-Accounts payable | (22) | 8 | (7) |
-Accrued compensation | 2 | 11 | (3) |
-Over recovered regulatory clause revenues | 22 | 0 | (17) |
-Other current liabilities | (2) | (5) | (6) |
Net cash provided from operating activities | 460 | 344 | 331 |
Investing Activities: | |||
Property additions | (235) | (348) | (293) |
Cost of removal, net of salvage | (10) | (13) | (14) |
Change in construction payables | (28) | 12 | 7 |
Payments pursuant to long-term service agreements | (8) | (8) | (7) |
Other investing activities | 0 | (1) | 0 |
Net cash used for investing activities | (281) | (358) | (307) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | 32 | (26) | 12 |
Proceeds -- | |||
Common stock issuances | 20 | 50 | 40 |
Capital contributions from parent company | 4 | 4 | 3 |
Preference stock | 0 | 0 | 50 |
Pollution control revenue bonds issuances and remarketings | 13 | 42 | 63 |
Senior note issuances | 0 | 200 | 90 |
Redemptions and repurchases -- | |||
Pollution control revenue bonds | (13) | (29) | (76) |
Senior notes | (60) | (75) | (90) |
Payment of preferred and preference stock dividends | (9) | (9) | (7) |
Payment of common stock dividends | (130) | (123) | (115) |
Other financing activities | (1) | (3) | (4) |
Net cash provided from (used for) financing activities | (144) | 31 | (34) |
Net Change in Cash and Cash Equivalents | 35 | 17 | (10) |
Cash and Cash Equivalents at Beginning of Year | 39 | 22 | 32 |
Cash and Cash Equivalents at End of Year | 74 | 39 | 22 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 52 | 48 | 53 |
Income taxes (net of refunds) | (7) | 44 | (11) |
Noncash transactions - | |||
Accrued property additions at year-end | 20 | 42 | 32 |
Mississippi Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | (6) | (327) | (475) |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 126 | 104 | 92 |
Deferred income taxes | 777 | 145 | (396) |
Investment tax credits | (210) | (38) | 144 |
Allowance for equity funds used during construction | (110) | (136) | (122) |
Pension, postretirement, and other employee benefits | 10 | (29) | 14 |
Regulatory assets associated with Kemper IGCC | (61) | (72) | (35) |
Estimated loss on Kemper IGCC | 365 | 868 | 1,102 |
Income taxes receivable, non-current | (544) | 0 | 0 |
Amortization of Deferred Investment Tax Credits | (1) | ||
Other, net | (2) | 18 | 107 |
Changes in certain current assets and liabilities -- | |||
-Receivables | 28 | (22) | (25) |
-Fossil fuel stock | (4) | 13 | 63 |
-Materials and supplies | (13) | (15) | (11) |
-Prepaid income taxes | (35) | (50) | 17 |
-Other current assets | (1) | (4) | (4) |
-Accounts payable | (34) | 33 | 13 |
-Accrued interest | (2) | 29 | 17 |
-Accrued taxes | (11) | 39 | 11 |
-Over recovered regulatory clause revenues | 96 | (18) | (59) |
-Mirror CWIP | (271) | 180 | 0 |
-Customer liability associated with Kemper refunds | 73 | 0 | 0 |
-Other current liabilities | 2 | 17 | (5) |
Net cash provided from operating activities | 173 | 735 | 448 |
Investing Activities: | |||
Property additions | (857) | (1,257) | (1,641) |
Investment in restricted cash | 0 | (11) | 0 |
Distribution of restricted cash | 0 | 11 | 0 |
Cost of removal, net of salvage | (14) | (13) | (10) |
Change in construction payables | (9) | (50) | (50) |
Proceeds from asset sales | 0 | 0 | 79 |
Other investing activities | (26) | (20) | 19 |
Net cash used for investing activities | (906) | (1,340) | (1,603) |
Proceeds -- | |||
Capital contributions from parent company | 277 | 451 | 1,077 |
Bonds-Other | 0 | 23 | 42 |
Interest-bearing refundable deposit related to asset sale | 0 | 125 | 0 |
Long-term debt issuance to parent company | 275 | 220 | 0 |
Other long-term debt issuances | 0 | 250 | 475 |
Short-term borrowings | 505 | 0 | 0 |
Redemptions and repurchases -- | |||
Bonds-Other | 0 | (34) | (83) |
Senior notes | 0 | 0 | (50) |
Other long-term debt | (350) | (220) | (125) |
Return of paid in capital | 0 | (220) | (105) |
Payment of preferred and preference stock dividends | (2) | (2) | (2) |
Payment of common stock dividends | 0 | 0 | (72) |
Other financing activities | (7) | 0 | (2) |
Net cash provided from (used for) financing activities | 698 | 593 | 1,155 |
Net Change in Cash and Cash Equivalents | (35) | (12) | 0 |
Cash and Cash Equivalents at Beginning of Year | 133 | 145 | 145 |
Cash and Cash Equivalents at End of Year | 98 | 133 | 145 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 45 | 7 | 20 |
Income taxes (net of refunds) | (33) | (379) | (134) |
Noncash transactions - | |||
Accrued property additions at year-end | 105 | 114 | 165 |
Capital lease obligation | 0 | 0 | 83 |
Issuance of Promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | 301 | 0 | 0 |
Southern Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 229 | 175 | 166 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 254 | 225 | 183 |
Deferred income taxes | 42 | (168) | 171 |
Investment tax credits | 162 | 74 | 158 |
Amortization of Deferred Investment Tax Credits | (19) | (11) | (6) |
Deferred revenues | (15) | (21) | (18) |
Increase (Decrease) in Accrued Taxes Payable | 109 | 0 | 0 |
Other, net | 13 | 11 | 4 |
Changes in certain current assets and liabilities -- | |||
-Receivables | 18 | (26) | (11) |
-Prepaid income taxes | (26) | 35 | (30) |
-Other current assets | (4) | (8) | (8) |
-Accounts payable | (19) | 30 | (12) |
-Accrued taxes | 269 | 284 | 0 |
-Other current liabilities | (10) | 3 | 7 |
Net cash provided from operating activities | 1,003 | 603 | 604 |
Investing Activities: | |||
Plant acquisitions | (1,719) | (731) | (132) |
Property additions | (1,005) | (21) | (501) |
Investment in restricted cash | (159) | 0 | 0 |
Distribution of restricted cash | 154 | 0 | 0 |
Change in construction payables, net of joint owner portion | 251 | 0 | (4) |
Payments pursuant to long-term service agreements | (82) | (61) | (57) |
Other investing activities | 22 | (1) | (2) |
Net cash used for investing activities | (2,538) | (814) | (696) |
Financing Activities: | |||
Increase (decrease) in notes payable, net | (58) | 195 | (71) |
Proceeds -- | |||
Capital contributions from parent company | 646 | 146 | 1 |
Senior note issuances | 1,650 | 0 | 300 |
Other long-term debt issuances | 402 | 10 | 24 |
Redemptions and repurchases -- | |||
Senior notes | (525) | 0 | 0 |
Other long-term debt | (4) | (10) | (9) |
Distributions to noncontrolling interests | (18) | (1) | (1) |
Capital contributions from noncontrolling interests | 341 | 8 | 17 |
Payment of common stock dividends | (131) | (131) | (129) |
Other financing activities | (13) | 0 | 0 |
Net cash provided from (used for) financing activities | 2,290 | 217 | 132 |
Net Change in Cash and Cash Equivalents | 755 | 6 | 40 |
Cash and Cash Equivalents at Beginning of Year | 75 | 69 | 29 |
Cash and Cash Equivalents at End of Year | 830 | 75 | 69 |
Supplemental Cash Flow Information: | |||
Interest, net of amounts capitalized | 74 | 85 | 60 |
Income taxes (net of refunds) | (518) | (220) | (226) |
Noncash transactions - | |||
Accrued property additions at year-end | 257 | 1 | 6 |
Acquisitions | 0 | 229 | 0 |
Capital contributions from noncontrolling interests | $ 0 | $ 221 | $ 0 |
Consolidated Statements of Cas6
Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net cash paid for capitalized interest | $ 124 | $ 111 | $ 92 |
Alabama Power [Member] | |||
Net cash paid for capitalized interest | 22 | 18 | 11 |
Georgia Power [Member] | |||
Net cash paid for capitalized interest | 16 | 18 | 14 |
Gulf Power [Member] | |||
Net cash paid for capitalized interest | 6 | 5 | 3 |
Mississippi Power [Member] | |||
Net cash paid for capitalized interest | 66 | 69 | 54 |
Southern Power [Member] | |||
Net cash paid for capitalized interest | $ 14 | $ 0 | $ 9 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash and cash equivalents | $ 1,404 | $ 710 |
Receivables -- | ||
Customer accounts receivable | 1,058 | 1,090 |
Unbilled revenues | 397 | 432 |
Under recovered regulatory clause revenues | 63 | 136 |
Other accounts and notes receivable | 398 | 307 |
Accumulated provision for uncollectible accounts | (13) | (18) |
Income taxes receivable, current | 144 | 0 |
Fossil fuel stock, at average cost | 868 | 930 |
Materials and supplies, at average cost | 1,061 | 1,039 |
Vacation pay | 178 | 177 |
Prepaid expenses | 495 | 665 |
Other regulatory assets, current | 402 | 346 |
Other current assets | 71 | 50 |
Total current assets | 6,526 | 5,864 |
Property, Plant, and Equipment: | ||
In service | 75,118 | 70,013 |
Less accumulated depreciation | 24,253 | 24,059 |
Plant in service, net of depreciation | 50,865 | 45,954 |
Other utility plant, net | 233 | 211 |
Nuclear fuel, at amortized cost | 934 | 911 |
Construction work in progress | 9,082 | 7,792 |
Total property, plant, and equipment | 61,114 | 54,868 |
Other Property and Investments: | ||
Nuclear decommissioning trusts, at fair value | 1,512 | 1,546 |
Leveraged leases | 755 | 743 |
Miscellaneous property and investments | 485 | 203 |
Total other property and investments | 2,752 | 2,492 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 1,560 | 1,510 |
Unamortized loss on reacquired debt | 227 | 243 |
Other regulatory assets, deferred | 4,989 | 4,334 |
Income taxes receivable, non-current | 413 | 0 |
Other deferred charges and assets | 737 | 922 |
Total deferred charges and other assets | 7,926 | 7,009 |
Total Assets | 78,318 | 70,233 |
Current Liabilities: | ||
Securities due within one year | 2,674 | 3,329 |
Interest-bearing refundable deposits | 0 | 275 |
Notes payable | 1,376 | 803 |
Accounts payable | 1,905 | 1,593 |
Customer deposits | 404 | 390 |
Accrued taxes -- | ||
Accrued income taxes | 19 | 149 |
Other accrued taxes | 484 | 487 |
Accrued interest | 249 | 295 |
Accrued vacation pay | 228 | 223 |
Accrued compensation | 549 | 576 |
Asset retirement obligations, current | 217 | 32 |
Liabilities from risk management activities | 156 | 138 |
Other regulatory liabilities, current | 278 | 26 |
Mirror CWIP | 0 | 271 |
Other current liabilities | 590 | 374 |
Total current liabilities | 9,129 | 8,961 |
Senior notes - | ||
Unamortized Debt Issuance Expense | 241 | 202 |
Long-term Debt | 24,688 | 20,644 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 12,322 | 11,082 |
Deferred credits related to income taxes | 187 | 192 |
Accumulated deferred investment tax credits | 1,219 | 1,208 |
Employee benefit obligations | 2,582 | 2,432 |
Asset retirement obligations | 3,542 | 2,168 |
Unrecognized tax benefits | 370 | 4 |
Other cost of removal obligations | 1,162 | 1,215 |
Other regulatory liabilities, deferred | 254 | 398 |
Other deferred credits and liabilities | 720 | 589 |
Total deferred credits and other liabilities | 22,358 | 19,288 |
Total Liabilities | 56,175 | 48,893 |
Redeemable Preferred Stock of Subsidiaries | 118 | 375 |
Redeemable Noncontrolling Interests | 43 | 39 |
Common Stockholders' Equity: | ||
Common stock | 4,572 | 4,539 |
Paid-in capital | 6,282 | 5,955 |
Retained earnings | 10,010 | 9,609 |
Accumulated other comprehensive loss | (130) | (128) |
Common Stockholders' Equity | 20,592 | 19,949 |
Stockholders' Equity Attributable to Noncontrolling Interest | 1,390 | 977 |
Total stockholders' equity | 21,982 | 20,926 |
Total Liabilities and Stockholders' Equity | $ 78,318 | $ 70,233 |
Commitments and Contingent Matters | ||
Alabama Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | $ 194 | $ 273 |
Receivables -- | ||
Customer accounts receivable | 332 | 345 |
Unbilled revenues | 119 | 138 |
Under recovered regulatory clause revenues | 43 | 74 |
Other accounts and notes receivable | 20 | 23 |
Affiliated companies | 50 | 37 |
Accumulated provision for uncollectible accounts | (10) | (9) |
Income taxes receivable, current | 142 | 0 |
Fossil fuel stock, at average cost | 239 | 268 |
Materials and supplies, at average cost | 398 | 406 |
Vacation pay | 66 | 65 |
Prepaid expenses | 83 | 224 |
Other regulatory assets, current | 115 | 84 |
Other current assets | 10 | 6 |
Total current assets | 1,801 | 1,934 |
Property, Plant, and Equipment: | ||
In service | 24,750 | 23,080 |
Less accumulated depreciation | 8,736 | 8,522 |
Plant in service, net of depreciation | 16,014 | 14,558 |
Nuclear fuel, at amortized cost | 363 | 348 |
Construction work in progress | 801 | 1,006 |
Total property, plant, and equipment | 17,178 | 15,912 |
Other Property and Investments: | ||
Equity investments in unconsolidated subsidiaries | 71 | 66 |
Nuclear decommissioning trusts, at fair value | 737 | 756 |
Miscellaneous property and investments | 96 | 84 |
Total other property and investments | 904 | 906 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 522 | 525 |
Deferred under recovered regulatory clause revenues | 99 | 31 |
Other regulatory assets, deferred | 1,114 | 1,063 |
Other deferred charges and assets | 103 | 122 |
Total deferred charges and other assets | 1,838 | 1,741 |
Total Assets | 21,721 | 20,493 |
Current Liabilities: | ||
Securities due within one year | 200 | 454 |
Notes payable | 0 | 0 |
Accounts payable - Affiliated | 278 | 248 |
Accounts payable - Other | 410 | 443 |
Customer deposits | 88 | 87 |
Accrued taxes -- | ||
Accrued income taxes | 38 | 37 |
Accrued interest | 73 | 66 |
Accrued vacation pay | 55 | 54 |
Accrued compensation | 119 | 131 |
Liabilities from risk management activities | 55 | 40 |
Other regulatory liabilities, current | 240 | 2 |
Other current liabilities | 39 | 40 |
Total current liabilities | 1,595 | 1,602 |
Senior notes - | ||
Unamortized debt premium (discount), net | (9) | (7) |
Unamortized Debt Issuance Expense | 45 | 39 |
Long-term Debt | 6,654 | 6,137 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 4,241 | 3,857 |
Deferred credits related to income taxes | 70 | 72 |
Accumulated deferred investment tax credits | 118 | 125 |
Employee benefit obligations | 388 | 326 |
Asset retirement obligations | 1,448 | 829 |
Other cost of removal obligations | 722 | 744 |
Other regulatory liabilities, deferred | 136 | 239 |
Deferred over recovered regulatory clause revenues | 0 | 47 |
Other deferred credits and liabilities | 76 | 78 |
Total deferred credits and other liabilities | 7,199 | 6,317 |
Total Liabilities | 15,448 | 14,056 |
Redeemable Preferred Stock of Subsidiaries | 85 | 342 |
Redeemable Preferred Stock | 85 | 342 |
Preference Stock | 196 | 343 |
Common Stockholders' Equity: | ||
Common stock | 1,222 | 1,222 |
Paid-in capital | 2,341 | 2,304 |
Retained earnings | 2,461 | 2,255 |
Accumulated other comprehensive loss | (32) | (29) |
Common Stockholders' Equity | 5,992 | 5,752 |
Total stockholders' equity | 5,992 | 5,752 |
Total Liabilities and Stockholders' Equity | $ 21,721 | $ 20,493 |
Commitments and Contingent Matters | ||
Georgia Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | $ 67 | $ 24 |
Receivables -- | ||
Customer accounts receivable | 541 | 553 |
Unbilled revenues | 188 | 201 |
Joint owner accounts receivable | 227 | 121 |
Other accounts and notes receivable | 57 | 61 |
Affiliated companies | 18 | 18 |
Accumulated provision for uncollectible accounts | (2) | (6) |
Income taxes receivable, current | 114 | 0 |
Fossil fuel stock, at average cost | 402 | 439 |
Materials and supplies, at average cost | 449 | 438 |
Vacation pay | 91 | 91 |
Prepaid income taxes | 156 | 244 |
Other regulatory assets, current | 123 | 136 |
Other current assets | 92 | 74 |
Total current assets | 2,523 | 2,394 |
Property, Plant, and Equipment: | ||
In service | 31,841 | 31,083 |
Less accumulated depreciation | 10,903 | 11,222 |
Plant in service, net of depreciation | 20,938 | 19,861 |
Other utility plant, net | 171 | 211 |
Nuclear fuel, at amortized cost | 572 | 563 |
Construction work in progress | 4,775 | 4,031 |
Total property, plant, and equipment | 26,456 | 24,666 |
Other Property and Investments: | ||
Equity investments in unconsolidated subsidiaries | 64 | 58 |
Nuclear decommissioning trusts, at fair value | 775 | 789 |
Miscellaneous property and investments | 43 | 38 |
Total other property and investments | 882 | 885 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 679 | 698 |
Deferred under recovered regulatory clause revenues | 0 | 197 |
Other regulatory assets, deferred | 2,152 | 1,753 |
Other deferred charges and assets | 173 | 279 |
Total deferred charges and other assets | 3,004 | 2,927 |
Total Assets | 32,865 | 30,872 |
Current Liabilities: | ||
Securities due within one year | 712 | 1,150 |
Notes payable | 158 | 156 |
Accounts payable - Affiliated | 411 | 451 |
Accounts payable - Other | 750 | 555 |
Customer deposits | 264 | 253 |
Accrued taxes -- | ||
Accrued income taxes | 12 | 0 |
Other accrued taxes | 325 | 332 |
Accrued interest | 99 | 96 |
Accrued vacation pay | 62 | 63 |
Accrued compensation | 142 | 153 |
Asset retirement obligations, current | 179 | 32 |
Liabilities from risk management activities | 12 | 32 |
Other regulatory liabilities, current | 16 | 21 |
Over recovered regulatory clause revenues, current | 10 | 0 |
Other current liabilities | 143 | 172 |
Total current liabilities | 3,295 | 3,466 |
Senior notes - | ||
Unamortized debt premium (discount), net | (10) | (11) |
Unamortized Debt Issuance Expense | 118 | 124 |
Long-term Debt | 9,616 | 8,563 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 5,627 | 5,474 |
Deferred credits related to income taxes | 105 | 106 |
Accumulated deferred investment tax credits | 204 | 196 |
Employee benefit obligations | 949 | 903 |
Deferred capacity expense | 203 | 167 |
Asset retirement obligations | 1,737 | 1,223 |
Other cost of removal obligations | 16 | 46 |
Other deferred credits and liabilities | 331 | 208 |
Total deferred credits and other liabilities | 8,969 | 8,156 |
Total Liabilities | 21,880 | 20,185 |
Redeemable Preferred Stock | 45 | 45 |
Preference Stock | 221 | 221 |
Common Stockholders' Equity: | ||
Common stock | 398 | 398 |
Paid-in capital | 6,275 | 6,196 |
Retained earnings | 4,061 | 3,835 |
Accumulated other comprehensive loss | (15) | (8) |
Common Stockholders' Equity | 10,719 | 10,421 |
Total stockholders' equity | 10,719 | 10,421 |
Total Liabilities and Stockholders' Equity | $ 32,865 | $ 30,872 |
Commitments and Contingent Matters | ||
Gulf Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | $ 74 | $ 39 |
Receivables -- | ||
Customer accounts receivable | 76 | 73 |
Unbilled revenues | 54 | 58 |
Under recovered regulatory clause revenues | 20 | 57 |
Other accounts and notes receivable | 9 | 8 |
Affiliated companies | 1 | 10 |
Accumulated provision for uncollectible accounts | (1) | (2) |
Income taxes receivable, current | 27 | 0 |
Fossil fuel stock, at average cost | 108 | 101 |
Materials and supplies, at average cost | 56 | 56 |
Prepaid expenses | 8 | 37 |
Other regulatory assets, current | 90 | 74 |
Other current assets | 14 | 2 |
Total current assets | 536 | 513 |
Property, Plant, and Equipment: | ||
In service | 5,045 | 4,495 |
Less accumulated depreciation | 1,296 | 1,296 |
Plant in service, net of depreciation | 3,749 | 3,199 |
Other utility plant, net | 62 | 0 |
Construction work in progress | 48 | 465 |
Total property, plant, and equipment | 3,859 | 3,664 |
Other Property and Investments: | ||
Total other property and investments | 4 | 15 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 61 | 56 |
Other regulatory assets, deferred | 427 | 416 |
Other deferred charges and assets | 33 | 33 |
Total deferred charges and other assets | 521 | 505 |
Total Assets | 4,920 | 4,697 |
Current Liabilities: | ||
Securities due within one year | 110 | 0 |
Notes payable | 142 | 110 |
Accounts payable - Affiliated | 55 | 87 |
Accounts payable - Other | 44 | 56 |
Customer deposits | 36 | 35 |
Accrued taxes -- | ||
Accrued income taxes | 4 | 0 |
Other accrued taxes | 9 | 9 |
Accrued interest | 9 | 11 |
Accrued compensation | 25 | 23 |
Deferred capacity expense, current | 22 | 22 |
Liabilities from risk management activities | 49 | 37 |
Other regulatory liabilities, current | 22 | 1 |
Other current liabilities | 40 | 22 |
Total current liabilities | 567 | 413 |
Senior notes - | ||
Unamortized debt premium (discount), net | (8) | (9) |
Unamortized Debt Issuance Expense | 8 | 8 |
Long-term Debt | 1,193 | 1,362 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 893 | 797 |
Employee benefit obligations | 129 | 121 |
Deferred capacity expense | 141 | 163 |
Asset retirement obligations | 113 | 17 |
Other cost of removal obligations | 233 | 235 |
Other regulatory liabilities, deferred | 47 | 48 |
Other deferred credits and liabilities | 102 | 85 |
Total deferred credits and other liabilities | 1,658 | 1,466 |
Total Liabilities | 3,418 | 3,241 |
Preference Stock | 147 | 147 |
Common Stockholders' Equity: | ||
Common stock | 503 | 483 |
Paid-in capital | 567 | 560 |
Retained earnings | 285 | 267 |
Accumulated other comprehensive loss | 0 | (1) |
Common Stockholders' Equity | 1,355 | 1,309 |
Total stockholders' equity | 1,355 | 1,309 |
Total Liabilities and Stockholders' Equity | $ 4,920 | $ 4,697 |
Commitments and Contingent Matters | ||
Mississippi Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | $ 98 | $ 133 |
Receivables -- | ||
Customer accounts receivable | 26 | 43 |
Unbilled revenues | 36 | 35 |
Other accounts and notes receivable | 10 | 11 |
Affiliated companies | 20 | 51 |
Income taxes receivable, current | 20 | 0 |
Fossil fuel stock, at average cost | 104 | 100 |
Materials and supplies, at average cost | 75 | 62 |
Prepaid income taxes | 39 | 70 |
Other regulatory assets, current | 95 | 73 |
Other current assets | 8 | 5 |
Total current assets | 531 | 583 |
Property, Plant, and Equipment: | ||
In service | 4,886 | 4,378 |
Less accumulated depreciation | 1,262 | 1,173 |
Plant in service, net of depreciation | 3,624 | 3,205 |
Construction work in progress | 2,254 | 2,161 |
Total property, plant, and equipment | 5,878 | 5,366 |
Other Property and Investments: | ||
Total other property and investments | 11 | 5 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 290 | 226 |
Other regulatory assets, deferred | 525 | 385 |
Income taxes receivable, non-current | 544 | 0 |
Accumulated deferred income taxes | 0 | 33 |
Other deferred charges and assets | 61 | 44 |
Total deferred charges and other assets | 1,420 | 688 |
Total Assets | 7,840 | 6,642 |
Current Liabilities: | ||
Securities due within one year | 728 | 778 |
Interest-bearing refundable deposits | 0 | 275 |
Notes payable | 500 | 0 |
Accounts payable - Affiliated | 85 | 86 |
Accounts payable - Other | 135 | 178 |
Customer deposits | 16 | 15 |
Accrued taxes -- | ||
Accrued income taxes | 0 | 142 |
Other accrued taxes | 85 | 84 |
Accrued interest | 18 | 76 |
Accrued compensation | 26 | 26 |
Over recovered regulatory clause liabilities | 96 | 1 |
Mirror CWIP | 0 | 271 |
Customer liability associated with Kemper refunds | 73 | 0 |
Other current liabilities | 74 | 46 |
Total current liabilities | 1,836 | 1,978 |
Senior notes - | ||
Unamortized Debt Issuance Expense | 8 | 9 |
Long-term Debt | 1,886 | 1,621 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 762 | 180 |
Deferred credits related to income taxes | 8 | 9 |
Accumulated deferred investment tax credits | 5 | 283 |
Employee benefit obligations | 153 | 148 |
Asset retirement obligations | 154 | 48 |
Unrecognized tax benefits | 368 | 2 |
Other cost of removal obligations | 165 | 166 |
Other regulatory liabilities, deferred | 71 | 64 |
Other deferred credits and liabilities | 40 | 26 |
Total deferred credits and other liabilities | 1,726 | 926 |
Total Liabilities | 5,448 | 4,525 |
Redeemable Preferred Stock | 33 | 33 |
Common Stockholders' Equity: | ||
Common stock | 38 | 38 |
Paid-in capital | 2,893 | 2,612 |
Retained earnings | (566) | (559) |
Accumulated other comprehensive loss | (6) | (7) |
Common Stockholders' Equity | 2,359 | 2,084 |
Total stockholders' equity | 2,359 | 2,084 |
Total Liabilities and Stockholders' Equity | $ 7,840 | $ 6,642 |
Commitments and Contingent Matters | ||
Southern Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | $ 830 | $ 75 |
Receivables -- | ||
Customer accounts receivable | 75 | 77 |
Other accounts and notes receivable | 19 | 15 |
Affiliated companies | 30 | 34 |
Fossil fuel stock, at average cost | 16 | 22 |
Materials and supplies, at average cost | 63 | 58 |
Prepaid income taxes | 45 | 19 |
Prepaid expenses | 23 | 17 |
Assets from risk management activities | 7 | 5 |
Total current assets | 1,108 | 322 |
Property, Plant, and Equipment: | ||
In service | 7,275 | 5,657 |
Less accumulated depreciation | 1,248 | 1,035 |
Plant in service, net of depreciation | 6,027 | 4,622 |
Construction work in progress | 1,137 | 11 |
Total property, plant, and equipment | 7,164 | 4,633 |
Other Property and Investments: | ||
Goodwill | 2 | 2 |
Other intangible assets, net of amortization | 317 | 47 |
Total other property and investments | 319 | 49 |
Deferred Charges and Other Assets: | ||
Prepaid long-term service agreements | 166 | 124 |
Other deferred charges and assets -- affiliated | 9 | 5 |
Other deferred charges and assets | 139 | 100 |
Total deferred charges and other assets | 314 | 229 |
Total Assets | 8,905 | 5,233 |
Current Liabilities: | ||
Securities due within one year | 403 | 525 |
Notes payable | 137 | 195 |
Accounts payable - Affiliated | 66 | 78 |
Accounts payable - Other | 327 | 30 |
Accrued taxes -- | ||
Accrued income taxes | 198 | 70 |
Other accrued taxes | 5 | 3 |
Accrued interest | 23 | 30 |
Contingent consideration | 36 | 8 |
Other current liabilities | 44 | 6 |
Total current liabilities | 1,239 | 945 |
Senior notes - | ||
Unamortized debt premium (discount), net | 0 | 2 |
Unamortized Debt Issuance Expense | 19 | 11 |
Long-term Debt | 2,719 | 1,085 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 601 | 559 |
Accumulated deferred investment tax credits | 889 | 601 |
Accrued income taxes, non-current | 109 | 0 |
Deferred capacity revenues -- affiliated | 17 | 15 |
Asset retirement obligations | 21 | 13 |
Other deferred credits and liabilities | 3 | 5 |
Total deferred credits and other liabilities | 1,640 | 1,193 |
Total Liabilities | 5,598 | 3,223 |
Redeemable Noncontrolling Interest | 43 | 39 |
Common Stockholders' Equity: | ||
Common stock | 0 | 0 |
Paid-in capital | 1,822 | 1,176 |
Retained earnings | 657 | 573 |
Accumulated other comprehensive loss | 4 | 3 |
Common Stockholders' Equity | 2,483 | 1,752 |
Stockholders' Equity Attributable to Noncontrolling Interest | 781 | 219 |
Total stockholders' equity | 3,264 | 1,971 |
Total Liabilities and Stockholders' Equity | $ 8,905 | $ 5,233 |
Commitments and Contingent Matters | ||
Southern Power [Member] | 1.85% due 2017 [Member] | ||
Senior notes - | ||
Senior notes | $ 500 | $ 0 |
Southern Power [Member] | 1.50% due 2018 [Member] | ||
Senior notes - | ||
Senior notes | 350 | 0 |
Southern Power [Member] | 2.375% due 2020 [Member] | ||
Senior notes - | ||
Senior notes | 300 | 0 |
Southern Power [Member] | 4.15% to 6.375% due Due 2025-2043 [Member] | ||
Senior notes - | ||
Senior notes | 1,575 | 1,075 |
Southern Power [Member] | 3.50% due 2032-2035 [Member] | ||
Senior notes - | ||
Other long-term notes - variable rate (3.50% at 1/1/16) due 2032-2035 | $ 13 | $ 19 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Common stock, par value per share (in dollars per share) | $ 5 | $ 5 |
Common stock, shares authorized | 1,500,000,000 | 1,500,000,000 |
Southern Power [Member] | ||
Amortization expense on other intangible assets | $ 12 | $ 9 |
Common stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000 | 1,000,000 |
Common stock, shares outstanding | 1,000 | 1,000 |
Southern Power [Member] | 1.85% due 2017 [Member] | ||
Fixed stated interest rate of debt obligation | 1.85% | 0.00% |
Southern Power [Member] | 1.50% due 2018 [Member] | ||
Fixed stated interest rate of debt obligation | 1.50% | 0.00% |
Southern Power [Member] | 2.375% due 2020 [Member] | ||
Fixed stated interest rate of debt obligation | 2.375% | 0.00% |
Southern Power [Member] | 4.15% to 6.375% due Due 2025-2043 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum | 4.15% | 4.15% |
Consolidated Statements of Capi
Consolidated Statements of Capitalization - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Maturity | ||
Total long term debt payable to affiliated trusts | $ 206 | $ 206 |
Long-term debt, due 2015 | 0 | 2,375 |
Long-term debt maturities, 2015 | 1,360 | 1,360 |
Long-term debt maturities, 2016 | 1,995 | 1,495 |
Long-term debt maturities, 2017 | 1,697 | 850 |
Long-term debt maturities, 2018 | 1,176 | 1,175 |
Long-term debt maturities, 2019 | 1,327 | 425 |
Long-term debt maturities, thereafter | 11,185 | 10,150 |
Long-term senior notes and debt: | ||
Total long -term senior notes and debt | 20,418 | 19,055 |
Pollution control revenue bonds -- | ||
Total other long -term debt | 6,808 | 4,719 |
Capitalized lease obligations | 146 | 159 |
Unamortized debt premium (related to plant acquisition) | 61 | 69 |
Unamortized debt discount | (36) | (33) |
Unamortized Debt Issuance Expense | (241) | (202) |
Total long-term debt (annual interest requirement ) | 27,362 | 23,973 |
Less amount due within one year | 2,674 | 3,329 |
Long-term debt excluding amount due within one year | $ 24,688 | $ 20,644 |
Percent capitalization | 52.60% | 49.20% |
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | $ 118 | $ 375 |
Total redeemable preferred stock - percent capitalization | 0.30% | 0.90% |
Preferred and preference stock of subsidiaries | $ 1,390 | $ 977 |
Total preferred and preference stock of subsidiaries - percent capitalization | 3.00% | 2.30% |
Redeemable Noncontrolling Interests | $ 43 | $ 39 |
Redeemable Noncontrolling Interest As Percent Of Capitalization | 0.10% | 0.10% |
Common Stockholders' Equity: | ||
Common stock | $ 4,572 | $ 4,539 |
Paid-in capital | 6,282 | 5,955 |
Treasury, at cost | (142) | (26) |
Retained earnings | 10,010 | 9,609 |
Accumulated other comprehensive loss | (130) | (128) |
Common Stockholders' Equity | $ 20,592 | $ 19,949 |
Total common stockholders' equity - percent capitalization | 44.00% | 47.50% |
Total stockholders' equity | $ 21,982 | $ 20,926 |
Total Capitalization | $ 46,831 | $ 41,984 |
Percent Capitalization | 100.00% | 100.00% |
Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | $ 81 | $ 81 |
Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 5.83% | |
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | $ 37 | 294 |
Noncumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 45 | 45 |
Preference Stock, $1 par value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 196 | 343 |
Preference Stock , $100 par or stated value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 368 | 368 |
Noncontrolling Interest [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 781 | 221 |
Adjustable Rate Loans [Member] | ||
Maturity | ||
Long-term debt, due 2015 | 0 | 775 |
Long-term debt maturities, 2015 | 1,278 | 450 |
Long-term debt maturities, 2016 | $ 400 | $ 0 |
Affiliate trusts, variable rate, due 2042 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 3.43% | 3.43% |
Pollution control revenue bonds due 2019 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 25 | $ 25 |
Pollution control revenue bonds due 2022 through 2049 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,509 | 1,466 |
Pollution control revenue bonds variable rate, Due 2015 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 0 | 152 |
Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 4 | 4 |
Pollution control revenue bonds variable rate, Due 2017 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 36 | 36 |
Maturity Of Pollution Control Bonds Variable Rate Due 2020 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 7 | 7 |
Pollution control revenue bonds variable rate, Due 2020 to 2052 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,757 | 1,559 |
Loan For Federal Financing Bank | 2,163 | 1,180 |
Plant Daniel revenue bonds due 2021 [Member] | ||
Pollution control revenue bonds -- | ||
Taxable Revenue Bonds | 270 | 270 |
Debt Due 2020 [Member] | ||
Pollution control revenue bonds -- | ||
Loan For Federal Financing Bank | 37 | 20 |
Maturity of Pollution Control Bonds Period Three [Member] | ||
Pollution control revenue bonds -- | ||
Junior Subordinated Notes, Noncurrent | 1,000 | 0 |
Alabama Power [Member] | ||
Maturity | ||
Total long term debt payable to affiliated trusts | 206 | 206 |
Long-term debt maturities, 2015 | 0 | 400 |
Long-term debt maturities, 2016 | 200 | 200 |
Long-term debt maturities, 2017 | 525 | 525 |
Long-term debt maturities, 2018 | 200 | 200 |
Long-term debt maturities, 2019 | 250 | 250 |
Long-term debt maturities, thereafter | 4,425 | 3,700 |
Long-term senior notes and debt: | ||
Total long-term notes payable | 5,600 | 5,275 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,100 | 1,200 |
Total other long -term debt | 1,097 | 1,151 |
Capitalized lease obligations | 5 | 5 |
Unamortized debt (discount), net | (9) | (7) |
Unamortized Debt Issuance Expense | (45) | (39) |
Total long-term debt (annual interest requirement ) | 6,854 | 6,591 |
Less amount due within one year | 200 | 454 |
Long-term debt excluding amount due within one year | $ 6,654 | $ 6,137 |
Percent capitalization | 51.40% | 48.80% |
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | $ 85 | $ 342 |
Preferred stock | 85 | 342 |
Preference stock | $ 196 | $ 343 |
Total redeemable preferred stock - percent capitalization | 0.70% | 2.70% |
Total preferred and preference stock of subsidiaries - percent capitalization | 1.50% | 2.70% |
Common Stockholders' Equity: | ||
Common stock | $ 1,222 | $ 1,222 |
Paid-in capital | 2,341 | 2,304 |
Retained earnings | 2,461 | 2,255 |
Accumulated other comprehensive loss | (32) | (29) |
Common Stockholders' Equity | $ 5,992 | $ 5,752 |
Total common stockholders' equity - percent capitalization | 46.40% | 45.80% |
Total stockholders' equity | $ 5,992 | $ 5,752 |
Total Capitalization | $ 12,927 | $ 12,574 |
Percent Capitalization | 100.00% | 100.00% |
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | $ 48 | $ 48 |
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | $ 37 | $ 294 |
Alabama Power [Member] | Affiliate trusts, variable rate, due 2042 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 3.43% | 3.43% |
Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 287 | $ 367 |
Alabama Power [Member] | Pollution control revenue bonds due 2015 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.03% | |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 0 | $ 54 |
Alabama Power [Member] | Pollution control revenue bonds variable rate, Due 2017 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 36 | 36 |
Alabama Power [Member] | Pollution control revenue bonds due 2021-2038 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 774 | 694 |
Georgia Power [Member] | ||
Maturity | ||
Long-term debt maturities, variable, 2016 | 450 | 450 |
Long-term debt maturities, 2015 | 0 | 1,050 |
Long-term debt maturities, 2016 | 250 | 250 |
Long-term debt maturities, 2017 | 450 | 450 |
Long-term debt maturities, 2018 | 747 | 250 |
Long-term debt maturities, 2019 | 502 | 500 |
Long-term debt maturities, thereafter | 3,850 | 3,975 |
Long-term senior notes and debt: | ||
Total long-term notes payable | 6,249 | 6,925 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,800 | 1,600 |
Total other long -term debt | 4,024 | 2,883 |
Capitalized lease obligations | 183 | 40 |
Unamortized debt (discount), net | (10) | (11) |
Unamortized Debt Issuance Expense | (118) | (124) |
Total long-term debt (annual interest requirement ) | 10,328 | 9,713 |
Less amount due within one year | 712 | 1,150 |
Long-term debt excluding amount due within one year | $ 9,616 | $ 8,563 |
Percent capitalization | 46.70% | 44.50% |
Redeemable Preferred and Preference Stock: | ||
Preferred stock | $ 45 | $ 45 |
Preference stock | $ 221 | $ 221 |
Total preferred and preference stock of subsidiaries - percent capitalization | 1.30% | 1.40% |
Common Stockholders' Equity: | ||
Common stock | $ 398 | $ 398 |
Paid-in capital | 6,275 | 6,196 |
Retained earnings | 4,061 | 3,835 |
Accumulated other comprehensive loss | (15) | (8) |
Common Stockholders' Equity | $ 10,719 | $ 10,421 |
Total common stockholders' equity - percent capitalization | 52.00% | 54.10% |
Total stockholders' equity | $ 10,719 | $ 10,421 |
Total Capitalization | $ 20,601 | $ 19,250 |
Percent Capitalization | 100.00% | 100.00% |
Georgia Power [Member] | Noncumulative Preferred Stock, $25 par value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred stock | $ 45 | $ 45 |
Georgia Power [Member] | Noncumulative Preferred Stock, $100 par value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 221 | 221 |
Georgia Power [Member] | Noncumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Total preferred and preference stock | 266 | 266 |
Georgia Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 952 | 818 |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2015 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 0 | $ 98 |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.22% | 0.22% |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 4 | $ 4 |
Georgia Power [Member] | Pollution control revenue bonds due 2022-2052 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 868 | 763 |
Georgia Power [Member] | Debt Due 2020 [Member] | ||
Pollution control revenue bonds -- | ||
Loan For Federal Financing Bank | 37 | 20 |
Georgia Power [Member] | Debt Due 2021-2044 [Member] | ||
Pollution control revenue bonds -- | ||
Loan For Federal Financing Bank | 2,163 | 1,180 |
Gulf Power [Member] | ||
Maturity | ||
Long-term debt maturities, 2015 | 110 | 110 |
Long-term debt maturities, 2016 | 85 | 85 |
Long-term debt maturities, 2019 | 175 | 175 |
Long-term debt maturities, thereafter | 640 | 700 |
Long-term senior notes and debt: | ||
Total long-term notes payable | 1,010 | 1,070 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 309 | 309 |
Total other long -term debt | 309 | 309 |
Unamortized debt (discount), net | (8) | (9) |
Unamortized Debt Issuance Expense | (8) | (8) |
Total long-term debt (annual interest requirement ) | 1,303 | 1,362 |
Less amount due within one year | 110 | 0 |
Long-term debt excluding amount due within one year | $ 1,193 | $ 1,362 |
Percent capitalization | 44.30% | 48.30% |
Redeemable Preferred and Preference Stock: | ||
Preference stock | $ 147 | $ 147 |
Total redeemable preferred stock - percent capitalization | 5.40% | 5.20% |
Common Stockholders' Equity: | ||
Common stock | $ 503 | $ 483 |
Paid-in capital | 567 | 560 |
Retained earnings | 285 | 267 |
Accumulated other comprehensive loss | 0 | (1) |
Common Stockholders' Equity | $ 1,355 | $ 1,309 |
Total common stockholders' equity - percent capitalization | 50.30% | 46.50% |
Total stockholders' equity | $ 1,355 | $ 1,309 |
Total Capitalization | $ 2,695 | $ 2,818 |
Percent Capitalization | 100.00% | 100.00% |
Gulf Power [Member] | 6% Preference stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | $ 54 | $ 54 |
Gulf Power [Member] | 6.45 % Preference stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 44 | 44 |
Gulf Power [Member] | 5.6% Preference Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 49 | 49 |
Gulf Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 227 | 240 |
Gulf Power [Member] | Pollution control revenue bonds due 2022-2039 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 82 | 69 |
Mississippi Power [Member] | ||
Maturity | ||
Long-term debt maturities, 2016 | 300 | 300 |
Long-term debt maturities, 2017 | 35 | 35 |
Long-term debt maturities, 2018 | 125 | 125 |
Long-term debt maturities, thereafter | 680 | 680 |
Bank term loans | 425 | 775 |
Long-term senior notes and debt: | ||
Total long-term notes payable | 1,565 | 1,915 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 83 | 83 |
Total other long -term debt | 929 | 353 |
Capitalized lease obligations | 77 | 79 |
Unamortized debt premium (related to plant acquisition) | 53 | 63 |
Unamortized debt discount | (2) | (2) |
Unamortized Debt Issuance Expense | (8) | (9) |
Total long-term debt (annual interest requirement ) | 2,614 | 2,399 |
Less amount due within one year | 728 | 778 |
Long-term debt excluding amount due within one year | $ 1,886 | $ 1,621 |
Percent capitalization | 44.10% | 43.30% |
Redeemable Preferred and Preference Stock: | ||
Preferred stock | $ 33 | $ 33 |
Total redeemable preferred stock - percent capitalization | 0.80% | 0.90% |
Common Stockholders' Equity: | ||
Common stock | $ 38 | $ 38 |
Paid-in capital | 2,893 | 2,612 |
Retained earnings | (566) | (559) |
Accumulated other comprehensive loss | (6) | (7) |
Common Stockholders' Equity | $ 2,359 | $ 2,084 |
Total common stockholders' equity - percent capitalization | 55.10% | 55.80% |
Total stockholders' equity | $ 2,359 | $ 2,084 |
Total Capitalization | $ 4,278 | $ 3,738 |
Percent Capitalization | 100.00% | 100.00% |
Mississippi Power [Member] | Pollution control revenue bonds due 2028 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 43 | $ 43 |
Mississippi Power [Member] | Maturity Of Pollution Control Bonds Variable Rate Due 2020 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.16% | 0.16% |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 7 | $ 7 |
Mississippi Power [Member] | Pollution control revenue bonds due 2020-2028 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | $ 33 | $ 33 |
Mississippi Power [Member] | Plant Daniel revenue bonds due 2021 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
Pollution control revenue bonds -- | ||
Taxable Revenue Bonds | $ 270 | $ 270 |
Mississippi Power [Member] | Maturity of Long-Term Debt Payable To Parent Company Period One [Member] | ||
Pollution control revenue bonds -- | ||
Long-term Debt Payable To Parent Company | $ 576 | $ 0 |
Consolidated Statements of Ca10
Consolidated Statements of Capitalization (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Annual interest requirement | $ 997 | |
Annual dividend requirement | $ 39 | |
Common stock, Par value (in dollars per share) | $ 5 | $ 5 |
Common stock, shares authorized | 1,500,000,000 | 1,500,000,000 |
Common stock, shares issued | 915,000,000 | 909,000,000 |
Treasury shares | 3,400,000 | 700,000 |
Redeemable Preferred Stock, $1 par value [Member] | ||
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 | 2,000,000 | 12,000,000 |
Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member] | ||
Fixed stated interest rate of debt obligation | 5.83% | |
Dividend Rate, Minimum | 5.20% | |
Dividend Rate, Maximum | 5.83% | |
Redeemable Preferred Stock, $100 par or stated value [Member] | ||
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 [Member] | Cumulative Preferred Stock [Member] | ||
Dividend Rate, Minimum | 4.20% | 4.20% |
Dividend Rate, Maximum | 5.44% | 5.44% |
Redeemable Preferred Stock, $25 stated value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
Preference Stock , $100 par or stated value [Member] | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Dividend Rate, Minimum | 5.60% | 5.60% |
Dividend Rate, Maximum | 6.50% | 6.50% |
Preference stock, shares outstanding | 4,000,000 | 4,000,000 |
Preference Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
Dividend Rate, Minimum | 6.45% | 5.63% |
Dividend Rate, Maximum | 6.50% | 6.50% |
Preference stock, shares authorized | 65,000,000 | 65,000,000 |
Preference stock, shares outstanding | 8,000,000 | 14,000,000 |
Redeemable Preferred Stock [Member] | ||
Annual dividend requirement | $ 6 | $ 6 |
Noncumulative Preferred Stock [Member] | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
Dividend Rate, Minimum | 6.00% | 6.00% |
Dividend Rate, Maximum | 6.13% | |
Preference stock, shares authorized | 60,000,000 | 60,000,000 |
Preference stock, shares outstanding | 2,000,000 | 2,000,000 |
2014 [Member] | ||
Interest Rates, Minimum | 5.50% | |
Interest Rates, Maximum | 5.25% | |
2015 [Member] | ||
Interest Rates, Minimum | 1.95% | 1.95% |
Interest Rates, Maximum | 5.30% | 5.30% |
Maturity of Long Term Senior Notes and Debt in Year Three [Member] | ||
Interest Rates, Minimum | 1.30% | 1.30% |
Interest Rates, Maximum | 5.90% | 5.90% |
Maturity of Pollution Control Revenue Bonds 2019 [Member] | ||
Fixed stated interest rate of debt obligation | 4.55% | 4.55% |
Maturity of Pollution Control Revenue Bonds 2022 through 2049 [Member] | ||
Interest Rates, Minimum | 0.28% | 0.28% |
Interest Rates, Maximum | 5.15% | 5.15% |
Pollution Control Revenue Bonds Due 2015 [Member] | ||
Interest Rates, Minimum | 0.03% | |
Interest Rates, Maximum | 0.04% | |
Pollution Control Revenue Bonds Due 2016 [Member] | ||
Fixed stated interest rate of debt obligation | 0.22% | 0.22% |
Pollution Control Revenue Bonds Due 2017 [Member] | ||
Interest Rates, Minimum | 0.05% | 0.05% |
Interest Rates, Maximum | 0.06% | 0.06% |
Pollution Control Revenue Bonds Due 2020 [Member] | ||
Fixed stated interest rate of debt obligation | 0.16% | 0.16% |
Pollution Control Revenue Bonds Due 2021 to 2053 [Member] | ||
Interest Rates, Minimum | 0.01% | 0.01% |
Interest Rates, Maximum | 0.27% | 0.27% |
Pollution Control Revenue Bonds Due 2021 [Member] | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
FFB Loans Due 2020 [Member] | ||
Interest Rates, Minimum | 3.00% | 3.00% |
Interest Rates, Maximum | 3.86% | 3.86% |
FFB Loans Due 2021 to 2044 [Member] | ||
Interest Rates, Minimum | 3.00% | 3.00% |
Interest Rates, Maximum | 3.86% | 3.86% |
FFB Loans Due 2075 [Member] | ||
Fixed stated interest rate of debt obligation | 6.25% | |
Maturity of Long Term Senior Notes and Debt in Year Five [Member] | ||
Interest Rates, Minimum | 1.50% | 1.50% |
Interest Rates, Maximum | 5.40% | 5.40% |
Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Interest Rates, Minimum | 2.15% | 2.15% |
Interest Rates, Maximum | 5.55% | 5.55% |
Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Interest Rates, Minimum | 2.38% | 2.38% |
Interest Rates, Maximum | 4.75% | 4.75% |
2020 through 2051 [Member] | ||
Interest Rates, Minimum | 1.63% | 1.63% |
Interest Rates, Maximum | 6.38% | 6.38% |
Affiliate trusts, variable rate, due 2042 [Member] | ||
Fixed stated interest rate of debt obligation | 3.43% | 3.43% |
Adjustable Rate Loans [Member] | 2014 [Member] | ||
Interest Rates, Minimum | 0.77% | |
Interest Rates, Maximum | 1.17% | |
Adjustable Rate Loans [Member] | 2015 [Member] | ||
Interest Rates, Minimum | 0.76% | 0.76% |
Interest Rates, Maximum | 3.50% | 3.50% |
Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member] | ||
Fixed stated interest rate of debt obligation | 1.74% | 1.74% |
Alabama Power [Member] | ||
Annual interest requirement | $ 275 | |
Annual dividend requirement | $ 13 | |
Common stock, Par value (in dollars per share) | $ 40 | $ 40 |
Common stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, shares outstanding | 30,537,500 | 30,537,500 |
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
Dividend Rate, Minimum | 5.83% | 5.20% |
Dividend Rate, Maximum | 5.83% | |
Redeemable Cumulative preferred stock, shares authorized | 27,500,000 | 27,500,000 |
Redeemable Cumulative preferred stock, shares outstanding | 1,520,000 | 12,000,000 |
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | ||
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 [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Dividend Rate, Minimum | 4.20% | 4.20% |
Dividend Rate, Maximum | 4.92% | 4.92% |
Alabama Power [Member] | Redeemable Preferred Stock, $25 stated value | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 25 | $ 25 |
Alabama Power [Member] | Preference Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 1 | $ 1 |
Dividend Rate, Minimum | 6.45% | 5.63% |
Dividend Rate, Maximum | 6.50% | 6.50% |
Alabama Power [Member] | Redeemable Preferred Stock [Member] | ||
Annual dividend requirement | $ 4 | |
Alabama Power [Member] | Noncumulative Preferred Stock [Member] | ||
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 | 8,000,000 | 14,000,000 |
Alabama Power [Member] | 2014 [Member] | ||
Fixed stated interest rate of debt obligation | 0.55% | |
Alabama Power [Member] | 2015 [Member] | ||
Fixed stated interest rate of debt obligation | 5.20% | 5.20% |
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Fixed stated interest rate of debt obligation | 5.125% | 5.125% |
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Fixed stated interest rate of debt obligation | 3.375% | 3.375% |
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty One to Two Thousand Forty Five [Member] | ||
Interest Rates, Minimum | 2.80% | 2.80% |
Interest Rates, Maximum | 6.125% | 6.125% |
Alabama Power [Member] | Maturity of Long Term Senior Notes And Debt Two Thousand Seventeen [Member] | ||
Interest Rates, Minimum | 5.50% | 5.50% |
Interest Rates, Maximum | 5.55% | 5.55% |
Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member] | ||
Interest Rates, Minimum | 0.28% | 0.28% |
Interest Rates, Maximum | 5.00% | 5.00% |
Alabama Power [Member] | Pollution control revenue bonds due 2021-2038 [Member] | ||
Interest Rates, Minimum | 0.01% | 0.01% |
Interest Rates, Maximum | 0.09% | 0.09% |
Alabama Power [Member] | Pollution control revenue bonds due 2015 [Member] | ||
Fixed stated interest rate of debt obligation | 0.03% | |
Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member] | ||
Interest Rates, Minimum | 0.05% | 0.05% |
Interest Rates, Maximum | 0.06% | 0.06% |
Alabama Power [Member] | Affiliate trusts, variable rate, due 2042 [Member] | ||
Fixed stated interest rate of debt obligation | 3.43% | 3.43% |
Georgia Power [Member] | ||
Annual interest requirement | $ 382 | |
Annual dividend requirement | $ 17 | |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares outstanding | 9,261,500 | 9,261,500 |
Georgia Power [Member] | Noncumulative Preferred Stock, $25 par value [Member] | ||
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 [Member] | Noncumulative Preferred Stock, $100 par value [Member] | ||
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 [Member] | 2014 [Member] | ||
Interest Rates, Minimum | 0.625% | |
Interest Rates, Maximum | 5.25% | |
Georgia Power [Member] | 2015 [Member] | ||
Fixed stated interest rate of debt obligation | 3.00% | 3.00% |
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member] | ||
Fixed stated interest rate of debt obligation | 5.70% | 5.70% |
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member] | ||
Interest Rates, Minimum | 1.95% | 1.95% |
Interest Rates, Maximum | 5.40% | 5.40% |
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Fixed stated interest rate of debt obligation | 4.25% | 4.25% |
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Two to Two Thousand Forty Three [Member] | ||
Interest Rates, Minimum | 2.85% | 2.85% |
Interest Rates, Maximum | 5.95% | 5.95% |
Georgia Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member] | ||
Interest Rates, Minimum | 0.76% | |
Interest Rates, Maximum | 0.83% | |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Fixed stated interest rate of debt obligation | 0.22% | 0.22% |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2015 [Member] | ||
Interest Rates, Minimum | 0.03% | |
Interest Rates, Maximum | 0.04% | |
Georgia Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Interest Rates, Minimum | 0.85% | 0.85% |
Interest Rates, Maximum | 4.00% | 4.00% |
Georgia Power [Member] | Debt Due 2021-2044 [Member] | ||
Interest Rates, Minimum | 3.00% | 3.00% |
Interest Rates, Maximum | 3.86% | 3.86% |
Georgia Power [Member] | Variable rate, Due 2022-2052 [Member] | ||
Interest Rates, Minimum | 0.10% | 0.10% |
Interest Rates, Maximum | 0.27% | 0.27% |
Georgia Power [Member] | Debt Due 2020 [Member] | ||
Interest Rates, Minimum | 3.00% | 3.00% |
Interest Rates, Maximum | 3.86% | 3.86% |
Gulf Power [Member] | ||
Annual interest requirement | $ 54 | |
Preference stock, shares authorized | 20,000,000 | 20,000,000 |
Annual dividend requirement | $ 9 | |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares outstanding | 5,642,717 | 5,442,717 |
Gulf Power [Member] | Preference Stock , $100 par or stated value [Member] | ||
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Preference stock, shares outstanding | 550,000 | 550,000 |
Gulf Power [Member] | Preference Stock Type Three [Member] | ||
Preference stock, shares outstanding | 450,000 | 450,000 |
Gulf Power [Member] | Preference Stock Type Four [Member] | ||
Preference stock, shares outstanding | 500,000 | 500,000 |
Gulf Power [Member] | Preference Stock, $1 par value [Member] | ||
Preference stock, shares authorized | 10,000,000 | 10,000,000 |
Gulf Power [Member] | 2015 [Member] | ||
Fixed stated interest rate of debt obligation | 5.30% | 5.30% |
Gulf Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member] | ||
Fixed stated interest rate of debt obligation | 5.90% | 5.90% |
Gulf Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Fixed stated interest rate of debt obligation | 4.75% | 4.75% |
Gulf Power [Member] | 2020-2051 [Member] | ||
Interest Rates, Minimum | 3.10% | 3.10% |
Interest Rates, Maximum | 5.75% | 5.75% |
Gulf Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Interest Rates, Minimum | 0.55% | 0.55% |
Interest Rates, Maximum | 4.45% | 4.45% |
Gulf Power [Member] | Pollution control revenue bonds due 2022-2039 [Member] | ||
Interest Rates, Minimum | 0.01% | 0.01% |
Interest Rates, Maximum | 0.12% | 0.12% |
Gulf Power [Member] | 6.0% preference stock [Member] | Preference Stock , $100 par or stated value [Member] | ||
Fixed stated interest rate of debt obligation | 6.00% | 6.00% |
Gulf Power [Member] | 6.45% preference stock [Member] | Preference Stock , $100 par or stated value [Member] | ||
Fixed stated interest rate of debt obligation | 6.45% | 6.45% |
Gulf Power [Member] | Five Point Six Percent Preference Stock [Member] | Preference Stock , $100 par or stated value [Member] | ||
Fixed stated interest rate of debt obligation | 5.60% | 5.60% |
Mississippi Power [Member] | ||
Annual interest requirement | $ 87 | |
Preferred Stock, Par or Stated Value Per Share (in dollars per share) | $ 100 | $ 100 |
Dividend Rate, Minimum | 4.40% | 4.40% |
Dividend Rate, Maximum | 5.25% | 5.25% |
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 [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member] | ||
Fixed stated interest rate of debt obligation | 2.35% | 2.35% |
Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member] | ||
Fixed stated interest rate of debt obligation | 5.60% | 5.60% |
Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Six [Member] | ||
Fixed stated interest rate of debt obligation | 5.55% | 5.55% |
Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Thirty Five Thousand Forty Two [Member] | ||
Interest Rates, Minimum | 1.63% | 1.63% |
Interest Rates, Maximum | 5.40% | 5.40% |
Mississippi Power [Member] | 2028 [Member] | ||
Fixed stated interest rate of debt obligation | 5.15% | 5.15% |
Mississippi Power [Member] | Pollution control revenue bonds due 2020-2028 [Member] | ||
Interest Rates, Minimum | 0.10% | |
Interest Rates, Maximum | 0.11% | |
Mississippi Power [Member] | Plant Daniel revenue bonds due 2021 [Member] | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Fifteen [Member] | ||
Interest Rates, Minimum | 1.84% | 1.84% |
Interest Rates, Maximum | 1.90% | 1.90% |
Mississippi Power [Member] | Maturity Of Pollution Control Bonds Variable Rate Due 2020 [Member] | ||
Fixed stated interest rate of debt obligation | 0.16% | 0.16% |
Mississippi Power [Member] | Maturity of Long-Term Debt Payable to Parent Company [Member] | ||
Interest Rates, Minimum | 1.49% | 1.49% |
Interest Rates, Maximum | 1.74% | 1.74% |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions | Total | Common Stock [Member] | Treasury Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | AOCI Attributable to Parent [Member] | Preferred And Preference Stock [Member] | Noncontrolling Interest [Member] | Alabama Power [Member] | Alabama Power [Member]Common Stock [Member] | Alabama Power [Member]Paid In Capital [Member] | Alabama Power [Member]Retained Earnings [Member] | Alabama Power [Member]AOCI Attributable to Parent [Member] | Georgia Power [Member] | Georgia Power [Member]Common Stock [Member] | Georgia Power [Member]Paid In Capital [Member] | Georgia Power [Member]Retained Earnings [Member] | Georgia Power [Member]AOCI Attributable to Parent [Member] | Gulf Power [Member] | Gulf Power [Member]Common Stock [Member] | Gulf Power [Member]Paid In Capital [Member] | Gulf Power [Member]Retained Earnings [Member] | Gulf Power [Member]AOCI Attributable to Parent [Member] | Mississippi Power [Member] | Mississippi Power [Member]Common Stock [Member] | Mississippi Power [Member]Paid In Capital [Member] | Mississippi Power [Member]Retained Earnings [Member] | Mississippi Power [Member]AOCI Attributable to Parent [Member] | Southern Power [Member] | Southern Power [Member]Common Stock [Member] | Southern Power [Member]Paid In Capital [Member] | Southern Power [Member]Retained Earnings [Member] | Southern Power [Member]AOCI Attributable to Parent [Member] | Southern Power [Member]Common Stockholder's Equity Not Including Noncontrolling Interest [Member] | Southern Power [Member]Noncontrolling Interest [Member] |
Beginning Balance, Shares at Dec. 31, 2012 | 877,803 | 10,035 | 31,000 | 9,000 | 5,000 | 1,000 | 0 | ||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2012 | $ 19,004 | $ 4,389 | $ (450) | $ 4,855 | $ 9,626 | $ (123) | $ 707 | $ 0 | $ 5,398 | $ 1,222 | $ 2,227 | $ 1,976 | $ (27) | $ 9,273 | $ 398 | $ 5,585 | $ 3,297 | $ (7) | $ 1,181 | $ 393 | $ 549 | $ 241 | $ (2) | $ 1,749 | $ 38 | $ 1,401 | $ 319 | $ (9) | $ 1,522 | $ 0 | $ 1,028 | $ 495 | $ (1) | $ 1,522 | $ 0 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 166 | 166 | 166 | ||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 1,644 | 1,644 | 712 | 712 | 1,174 | 1,174 | 124 | 124 | (477) | (477) | |||||||||||||||||||||||||
Capital contributions from parent company | 35 | 35 | 48 | 48 | 4 | 4 | 976 | 976 | 1 | 1 | 1 | ||||||||||||||||||||||||
Other comprehensive income (loss) | 48 | 48 | 1 | 1 | 2 | 2 | 1 | 1 | 1 | 1 | 4 | 4 | 4 | ||||||||||||||||||||||
Stock issued, shares | 14,930 | 4,443 | 0 | ||||||||||||||||||||||||||||||||
Stock issued | 765 | $ 72 | $ 203 | 441 | 49 | 40 | $ 40 | ||||||||||||||||||||||||||||
Stock-based compensation | 65 | 65 | |||||||||||||||||||||||||||||||||
Cash dividends on common stock | (1,762) | (1,762) | (644) | (644) | (907) | (907) | (115) | (115) | (72) | (72) | (129) | (129) | (129) | ||||||||||||||||||||||
Other, shares | (55) | ||||||||||||||||||||||||||||||||||
Other | 0 | $ (3) | 1 | 2 | 1 | 1 | |||||||||||||||||||||||||||||
Ending Balance, Shares at Dec. 31, 2013 | 892,733 | 5,647 | 31,000 | 9,000 | 5,000 | 1,000 | 0 | ||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 19,764 | $ 4,461 | $ (250) | 5,362 | 9,510 | (75) | 756 | 0 | 5,502 | $ 1,222 | 2,262 | 2,044 | (26) | 9,591 | $ 398 | 5,633 | 3,565 | (5) | 1,235 | $ 433 | 553 | 250 | (1) | 2,177 | $ 38 | 2,377 | (230) | (8) | 1,564 | $ 0 | 1,029 | 532 | 3 | 1,564 | 0 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 172 | 172 | 172 | ||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 1,963 | 1,963 | 761 | 761 | 1,225 | 1,225 | 140 | 140 | (329) | (329) | |||||||||||||||||||||||||
Capital contributions from parent company | 42 | 42 | 563 | 563 | 7 | 7 | 235 | 235 | 147 | 147 | 147 | ||||||||||||||||||||||||
Other comprehensive income (loss) | (53) | (53) | (3) | (3) | (3) | (3) | 0 | 1 | 1 | 0 | |||||||||||||||||||||||||
Stock issued, shares | 15,769 | 4,996 | 0 | ||||||||||||||||||||||||||||||||
Stock issued | 806 | $ 78 | $ 227 | 501 | 50 | $ 50 | 0 | ||||||||||||||||||||||||||||
Stock-based compensation | 86 | 86 | |||||||||||||||||||||||||||||||||
Cash dividends on common stock | (1,866) | (1,866) | (550) | (550) | (954) | (954) | (123) | (123) | (131) | (131) | (131) | ||||||||||||||||||||||||
Contributions from noncontrolling interests | 221 | 221 | 221 | 221 | |||||||||||||||||||||||||||||||
Net income (loss) attributable to noncontrolling interests | 2 | 2 | (2) | (2) | |||||||||||||||||||||||||||||||
Other, shares | (74) | ||||||||||||||||||||||||||||||||||
Other | 7 | $ (3) | 6 | 2 | 2 | (1) | (1) | ||||||||||||||||||||||||||||
Ending Balance, Shares at Dec. 31, 2014 | 908,502 | 725 | 31,000 | 9,000 | 5,000 | 1,000 | 0 | ||||||||||||||||||||||||||||
Ending 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 attributable to Southern Power Company | 215 | 215 | 215 | ||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 2,367 | 2,367 | 785 | 785 | 1,260 | 1,260 | 148 | 148 | (8) | (8) | |||||||||||||||||||||||||
Capital contributions from parent company | 37 | 37 | 79 | 79 | 7 | 7 | 281 | 281 | 646 | 646 | 646 | ||||||||||||||||||||||||
Other comprehensive income (loss) | (2) | (2) | (3) | (3) | (7) | (7) | 1 | 1 | 1 | 1 | 1 | 1 | 1 | ||||||||||||||||||||||
Stock issued, shares | 6,571 | 2,599 | 1,000 | ||||||||||||||||||||||||||||||||
Stock issued | 256 | $ 33 | 223 | 20 | $ 20 | ||||||||||||||||||||||||||||||
Stock-based compensation | 100 | 100 | |||||||||||||||||||||||||||||||||
Stock repurchased, at cost | (115) | $ (115) | |||||||||||||||||||||||||||||||||
Cash dividends on common stock | (1,959) | (1,959) | (571) | (571) | (1,034) | (1,034) | (130) | (130) | (131) | (131) | (131) | ||||||||||||||||||||||||
Preference stock redemptions | (150) | (150) | |||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 567 | 567 | 567 | 567 | |||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | (18) | (18) | (17) | (17) | |||||||||||||||||||||||||||||||
Net income (loss) attributable to noncontrolling interests | (12) | (12) | 12 | 12 | |||||||||||||||||||||||||||||||
Other, shares | (28) | ||||||||||||||||||||||||||||||||||
Other | (2) | $ (1) | 4 | (7) | (3) | (1) | (8) | (8) | 1 | 1 | |||||||||||||||||||||||||
Ending Balance, Shares at Dec. 31, 2015 | 915,073 | 3,352 | 31,000 | 9,000 | 6,000 | 1,000 | 0 | ||||||||||||||||||||||||||||
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 |
Consolidated Statements of St12
Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Statement of Stockholders' Equity [Abstract] | |||||||||||
Cash dividends (in dollars per share) | $ 0.5425 | $ 0.5425 | $ 0.5425 | $ 0.525 | $ 0.525 | $ 0.525 | $ 0.525 | $ 0.5075 | $ 2.1525 | $ 2.0825 | $ 2.0125 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the FERC, and the traditional operating companies are also subject to regulation by their respective state PSCs. As such, each of 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 their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. In June 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, as well as the current period. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $202 million as of December 31, 2014. These debt issuance costs were previously presented within unamortized debt issuance expense. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 6 and 10 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million , with $488 million to non-current accumulated deferred income taxes and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of Southern Company. See Note 5 for disclosures impacted by ASU 2015-17. Regulatory Assets and Liabilities The traditional operating companies are subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans $ 3,440 $ 3,469 (a,n) Deferred income tax charges 1,514 1,458 (b) Asset retirement obligations-asset 481 119 (b,n) Other regulatory assets 299 275 (k) Loss on reacquired debt 248 267 (c) Fuel-hedging-asset 225 202 (d,n) Kemper IGCC regulatory assets 216 148 (h) Vacation pay 178 177 (f,n) Deferred PPA charges 163 185 (e,n) Under recovered regulatory clause revenues 142 157 (g) Remaining net book value of retired assets 283 44 (o) Environmental remediation-asset 78 64 (j,n) Property damage reserves-asset 92 98 (i) Nuclear outage 88 99 (g) Other cost of removal obligations (1,177 ) (1,229 ) (b) Over recovered regulatory clause revenues (261 ) (48 ) (g) Deferred income tax credits (187 ) (192 ) (b) Property damage reserves-liability (178 ) (181 ) (l) Asset retirement obligations-liability (45 ) (130 ) (b,n) Other regulatory liabilities (35 ) (47 ) (m) Mirror CWIP — (271 ) (h) Total regulatory assets (liabilities), net $ 5,564 $ 4,664 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (b) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2015 , other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with Georgia Power's 2013 ARP. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years . (d) Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years . Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (e) Recovered over the life of the PPA for periods up to eight years . (f) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years . (h) For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." (i) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding six years . (j) Recovered through the environmental cost recovery clause when the remediation is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building leases, closure of Plant Scholz ash pond, Plant Daniel Units 3 and 4 regulatory assets, 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 15 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, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 15 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 not exceeding 11 years . In the event that a portion of a traditional operating company's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power," "Retail Regulatory Matters – Gulf Power, "and "Integrated Coal Gasification Combined Cycle" for additional information. Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Southern Company's electric utility subsidiaries have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Income and Other Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional operating companies are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. 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 production tax credits (PTC), which are recorded to income tax expense based on 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 2015 and will be carried forward and utilized in future years. In addition, Southern Company has subsidiaries with various state net operating loss (NOL) carryforwards, which could result in net state income tax benefits in the future, if utilized. See Note 5 to the financial statements 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: 2015 2014 (in millions) Generation $ 41,648 $ 37,892 Transmission 10,544 9,884 Distribution 17,670 17,123 General 4,377 4,198 Plant acquisition adjustment 123 123 Utility plant in service 74,362 69,220 Information technology equipment and software 222 244 Communications equipment 418 439 Other 116 110 Other plant in service 756 793 Total plant in service $ 75,118 $ 70,013 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle. The refueling cycles for Alabama Power's Plant Farley and Georgia Power's Plants Hatch and Vogtle Units 1 and 2 range from 18 to 24 months , depending on the unit. Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below: Asset Balances at December 31, 2015 2014 (in millions) Office building $ 61 $ 61 Nitrogen plant 83 83 Computer-related equipment 61 60 Gas pipeline 6 6 Less: Accumulated amortization (59 ) (49 ) Balance, net of amortization $ 152 $ 161 The amount of non-cash property additions recognized for the years ended December 31, 2015 , 2014 , and 2013 was $844 million , $528 million , and $411 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, 2015 , 2014 , and 2013 was $13 million , $25 million , and $107 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 3.0% in 2015 , 3.1% in 2014 , and 3.3% in 2013 . Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $23.7 billion and $23.5 billion at December 31, 2015 and 2014 , respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. Cost, net of salvage value, of these assets is depreciated on an hours or starts units-of-production basis. Plant in service as of December 31, 2015 and 2014 that is depreciated on a units-of-production basis was approximately $485 million and $470 million , respectively. Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP) and the 2013 ARP, Georgia Power amortized approximately $31 million in 2013 and $14 million in each of 2014 and 2015 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under "Retail Regulatory Matters – Alabama Power – Cost of Removal Accounting Order " and "– Gulf Power – Retail Base Rate Case " for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability by Alabama Power and Gulf Power, respectively. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years . Accumulated depreciation for other plant in service totaled $510 million and $533 million at December 31, 2015 and 2014 , respectively. Asset Retirement Obligations and Other Costs of Removal 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. Each traditional operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 and 2 – and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17, 2015 (CCR Rule), principally ash ponds. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 2,201 $ 2,018 Liabilities incurred 662 18 Liabilities settled (37 ) (17 ) Accretion 115 102 Cash flow revisions 818 80 Balance at end of year $ 3,759 $ 2,201 The increases in liabilities incurred and cash flow revisions in 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule and Georgia Power's updated nuclear decommissioning study. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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 or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional operating companies expect to continue to periodically update these estimates. The cash flow revisions in 2014 are primarily related to Alabama Power's and SEGCO's AROs associated with asbestos at their steam generation facilities. 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, 2015 and 2014 , approximately $76 million and $51 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 $78 million and $52 million at December 31, 2015 and 2014 , 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, 2015 , investment securities in the Funds totaled $1.5 billion , consisting of equity securities of $817 million , debt securities of $654 million , and $38 million of other securities. At December 31, 2014 , investment securities in the Funds totaled $1.5 billion , consisting of equity securities of $886 million , debt securities of $638 million , and $19 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool. Sales of the securities held in the Funds resulted in cash proceeds of $1.4 billion , $913 million , and $1.0 billion in 2015 , 2014 , and 2013 , respectively, all of which were reinvested. 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 losses on securities held in the Funds at December 31, 2015 . For 2014 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $98 million , which included $19 million related to unrealized gains and losses on securities held in the Funds at December 31, 2014 . For 2013 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million , which included $119 million related to unrealized gains on securities held in the Funds at December 31, 2013 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2015 and 2014 , the accumulated provisions for decommissioning were as follows: External Trust Funds Internal Reserves Total 2015 2014 2015 2014 2015 2014 (in millions) Plant Farley $ 734 $ 754 $ 20 $ 21 $ 754 $ 775 Plant Hatch 487 496 — — 487 496 Plant Vogtle Units 1 and 2 288 293 — — 288 293 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, 2015 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 through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an infl |
Alabama Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases 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. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $39 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 10 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-current accumulated deferred income taxes in the Company’s December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. 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 $438 million , $400 million , and $340 million during 2015 , 2014 , and 2013 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $243 million , $234 million , and $211 million during 2015 , 2014 , and 2013 , respectively. The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $11 million in 2015 , $13 million in 2014 , and $13 million in 2013 . Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $8 million in 2015, $34 million in 2014, and $27 million in 2013. See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. The transmission improvements were completed in 2014. The Company received $14 million in 2015 and expects to recover approximately $12 million a year from 2016 through 2023 through a tariff with Gulf Power. 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 2015 , 2014 , or 2013 . Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Deferred income tax charges $ 522 $ 525 (a,k) Loss on reacquired debt 75 80 (b) Vacation pay 66 65 (c,j) Under/(over) recovered regulatory clause revenues (97 ) 57 (d) Fuel-hedging losses 55 53 (e,j) Other regulatory assets 53 49 (f) Asset retirement obligations (40 ) (125 ) (a) Other cost of removal obligations (722 ) (744 ) (a) Deferred income tax credits (70 ) (72 ) (a) Nuclear outage 53 56 (d) Natural disaster reserve (75 ) (84 ) (h) Other regulatory liabilities (8 ) (17 ) (e,g) Retiree benefit plans 903 882 (i,j) Remaining net book value of retired assets 76 13 (l) Total regulatory assets (liabilities), net $ 791 $ 738 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years . (c) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years . (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three 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, 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, fuel-hedging gains and nuclear fuel disposal fee. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. Nuclear fuel disposal fees are recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The balance was transferred to Rate ECR in 2015. See Note 3 for additional information. (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 $17 million for 2015 and $18 million for 2014 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 . In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" for additional information. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. 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: 2015 2014 (in millions) Generation $ 12,820 $ 11,670 Transmission 3,773 3,579 Distribution 6,432 6,196 General 1,713 1,623 Plant acquisition adjustment 12 12 Total plant in service $ 24,750 $ 23,080 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 2015 , 3.3% in 2014 and 3.2% in 2013 . 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 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. The new rates resulted in the decrease in the composite depreciation rate for 2015. Asset Retirement Obligations and Other Costs of Removal 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 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 on April 17, 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 829 $ 730 Liabilities incurred 402 1 Liabilities settled (3 ) (3 ) Accretion 53 45 Cash flow revisions 167 56 Balance at end of year $ 1,448 $ 829 The increase in liabilities incurred and cash flow revisions in 2015 is primarily related to the Company's AROs associated with the impact of the CCR Rule on its ash and gypsum facilities. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The cash flow revisions in 2014 are primarily related to the Company's AROs associated with asbestos at its steam generation facilities. 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, 2015 , investment securities in the Funds totaled $734 million , consisting of equity securities of $521 million , debt securities of $191 million , and $22 million of other securities. At December 31, 2014 , investment securities in the Funds totaled $754 million , consisting of equity securities of $583 million , debt securities of $163 million , and $8 million of other securities. 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 $438 million , $244 million , and $279 million in 2015 , 2014 , and 2013 , respectively, all of which were reinvested. 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 . For 2014 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $54 million , which included $19 million related to unrealized gains on securities held in the Funds at December 31, 2014 . For 2013 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million , which included $85 million related to unrealized losses on securities held in the Funds at December 31, 2013 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, the accumulated provisions for decommissioning were as follows: 2015 2014 (in millions) External trust funds $ 734 $ 754 Internal reserves 20 21 Total $ 754 $ 775 Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2015 based on the most current study performed in 2013 for Plant Farley are as follows: Decommissioning periods: Beginning year 2037 Completion year 2076 (in millions) Site study costs: Radiated structures $ 1,362 Non-radiated structures 80 Total site study costs $ 1,442 The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0% . The next site study is expected to be conducted in 2018. Amounts previously contributed to the Funds are currently projected to be adequate to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.7% in 2015 , 8.8% in 2014 , and 9.1% in 2013 . AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 9.3% in 2015 , 7.9% in 2014 , and 5.4% in 2013 . Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities 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 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 d |
Georgia Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Georgia Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases 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. 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 June 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, as well as the current period. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers , revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $124 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Notes 6 and 10 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid income taxes of $34 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. 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 $585 million in 2015 , $555 million in 2014 , and $504 million in 2013 . Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business, operations, and construction management. Costs for these services amounted to $681 million in 2015 , $643 million in 2014 , and $555 million in 2013 . The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $179 million , $144 million , and $136 million in 2015 , 2014 , and 2013 , respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2015 and 2014 . See Note 7 under "Fuel and Purchased Power Agreements" for additional information. The Company has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $12 million in 2015 , $9 million in 2014 , and $10 million in 2013 . See Note 4 for additional information. The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015 , 2014 , or 2013 . The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans $ 1,307 $ 1,325 (a, j) Deferred income tax charges 653 668 (b, j) Loss on reacquired debt 150 163 (c, j) Asset retirement obligations 411 108 (b, j) Vacation pay 91 91 (d, j) Cancelled construction projects 56 67 (e) Remaining net book value of retired assets 171 29 (f) Storm damage reserves 92 98 (g) Other regulatory assets 140 153 (h) Other cost of removal obligations (31 ) (60 ) (b) Deferred income tax credits (105 ) (106 ) (b, j) Other regulatory liabilities (2 ) (7 ) (i, j) Total regulatory assets (liabilities), net $ 2,933 $ 2,529 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 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2015, other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with the three-year amortization period approved in the Company's 2013 ARP. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years . (d) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (e) 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. (f) Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. Amortization of obsolete inventories will be determined by the Georgia PSC in the 2016 base rate case. (g) Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding six years or through 2019. (h) Comprised of several components including deferred nuclear outages, environmental remediation, Medicare subsidy deferred income tax charges, fuel hedging losses, building lease, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding 12 years or through 2022. (i) Comprised primarily of fuel-hedging gains, which upon final settlement are refunded through the Company's fuel cost recovery mechanism. (j) Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee" for additional information. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. Federal ITCs utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. State ITCs and other credits are recognized in the period in which the credits are claimed on the state income tax return. The Company had state investment and other tax credit carryforwards totaling $318 million , which will expire between 2018 and 2026 and are expected to be fully utilized by 2022. 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: 2015 2014 (in millions) Generation $ 15,386 $ 15,201 Transmission 5,355 5,086 Distribution 9,151 8,913 General 1,921 1,855 Plant acquisition adjustment 28 28 Total plant in service $ 31,841 $ 31,083 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 2015 , 2.7% in 2014 , and 3.0% in 2013 . 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 Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP) and the 2013 ARP, the Company amortized approximately $31 million in 2013 and $14 million in each of 2014 and 2015 of its remaining regulatory liability related to other cost of removal obligations. Asset Retirement Obligations and Other Costs of Removal 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 Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The ARO liability 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 on April 17, 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: 2015 2014 (in millions) Balance at beginning of year $ 1,255 $ 1,222 Liabilities incurred 6 9 Liabilities settled (30 ) (12 ) Accretion 56 53 Cash flow revisions 629 (17 ) Balance at end of year $ 1,916 $ 1,255 The increase in cash flow revisions in 2015 is primarily related to changes to the Company's ash ponds, landfill, and gypsum cell ARO closure dollar and timing estimates associated with the CCR Rule and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. In preparation for the Company's next rate case, and as a part of the Company's three -year ARO update cycle, new closure estimates were developed for ash ponds, landfills, gypsum cells, nuclear decommissioning, and asbestos AROs. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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 or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The 2014 decrease in cash flow revisions is primarily related to settled AROs for asbestos remediation. 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, 2015 and 2014 , approximately $76 million and $51 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 $78 million and $52 million at December 31, 2015 and 2014 , 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, 2015 , investment securities in the Funds totaled $775 million , consisting of equity securities of $296 million , debt securities of $463 million , and $16 million of other securities. At December 31, 2014 , investment securities in the Funds totaled $789 million , consisting of equity securities of $303 million , debt securities of $475 million , and $11 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool. Sales of the securities held in the Funds resulted in cash proceeds of $980 million , $669 million , and $705 million in 2015 , 2014 , and 2013 , respectively, all of which were reinvested. 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 losses on securities held in the Funds at December 31, 2015 . For 2014 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $44 million , which included an immaterial amount related to unrealized gains and losses on securities held in the Funds at December 31, 2014 . For 2013 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million , which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2013 . 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, 2015 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 $ 487 $ 288 For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4% . The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2015 , 2014 , and 2013 , the average AFUDC rates were 6.5% , 5.6% , and 5.3% , respectively, and AFUDC capitalized was $56 million , $62 million , and $44 million , respectively. AFUDC, net of income taxes, was 3.9% , 4.6% , and 3.3% of net income after dividends on preferred and preference stock for 2015 , 2014 , and 2013 , respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Storm Damage Recovery The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2015 and December 31, 2014 , the balance in the regulatory asset related to storm damage was $92 million and $98 million , respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62 million and $68 million included in other regulatory assets, deferred, re |
Gulf Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Gulf Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. The equity method is used for entities in which the Company has significant influence but does not control. The Company is subject to regulation by the FERC and the Florida PSC. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $8 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Note 2 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $3 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. 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 $78 million during 2015 , 2014 , and 2013 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $12 million , $9 million , and $10 million and Mississippi Power $27 million , $31 million , and $17 million in 2015 , 2014 , and 2013 , respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. The Company has an agreement with Alabama Power under which Alabama Power has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. The transmission improvements were completed in 2014. The Company expects to pay Alabama Power approximately $12 million a year from 2016 through 2023 for these improvements. Payments by the Company to Alabama Power were $14 million , $12 million , and $8 million in 2015 , 2014 , and 2013 , respectively, for the improvements. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff. The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015 , 2014 , or 2013 . The traditional operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) PPA charges $ 163 $ 185 (j,k) Retiree benefit plans, net 147 148 (i,j) Fuel-hedging assets, net 104 73 (g,j) Deferred income tax charges 59 53 (a) Environmental remediation 46 48 (h,j) Regulatory asset, offset to other cost of removal 29 8 (m) Closure of Plant Scholz ash pond 29 — (h,j) Loss on reacquired debt 15 16 (c) Vacation pay 10 10 (d,j) Deferred return on transmission upgrades 10 — (m) Other regulatory assets, net 7 9 (l) Deferred income tax charges — Medicare subsidy 2 3 (b) Under recovered regulatory clause revenues 1 53 (e) Other cost of removal obligations (262 ) (243 ) (a) Property damage reserve (38 ) (35 ) (f) Over recovered regulatory clause revenues (22 ) — (e) Deferred income tax credits (3 ) (4 ) (a) Asset retirement obligations, net (1 ) (5 ) (a,j) Total regulatory assets (liabilities), net $ 296 $ 319 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered and amortized over periods not exceeding 14 years . (c) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years . (d) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (e) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . (f) Recorded and recovered or amortized as approved by the Florida PSC. (g) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years . Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (h) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (i) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Recovered over the life of the PPA for periods up to eight years . (l) Comprised primarily of net book value of retired meters and recovery of injuries and damages costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years . (m) Recorded as authorized by the Florida PSC in the settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. 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: 2015 2014 (in millions) Generation $ 2,974 $ 2,638 Transmission 691 516 Distribution 1,196 1,157 General 182 182 Plant acquisition adjustment 2 2 Total plant in service $ 5,045 $ 4,495 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. On February 6, 2015, the Company announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 ( 357 MWs) by March 31, 2016, as a result of the cost to comply with environmental regulations imposed by the EPA. In connection with this retirement, the Company reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. The net book value of these units at December 31, 2015 was approximately $62 million . 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% in 2015 and 3.6% in both 2014 and 2013 . Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. As authorized by the Florida PSC in the 2013 Rate Case Settlement Agreement, the Company is 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 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional information. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations (ARO) are computed as the present value of the 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 on April 17, 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 in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 17 $ 16 Liabilities incurred 105 — Liabilities settled (1 ) — Accretion 2 1 Cash flow revisions 7 — Balance at end of year $ 130 $ 17 The increase in liabilities incurred in 2015 is primarily related to AROs associated with the portion of the Company's steam generation facilities impacted by the CCR Rule. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 using various assumptions related to closure in place 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, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. In connection with permitting activity related to the coal ash pond at the retired Plant Scholz facility, the Company recorded additional AROs of $29 million . Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for both 2015 and 2014 and 6.26% for 2013 . AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 10.80% , 10.93% , and 6.87% for 2015 , 2014 , and 2013 , 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 . The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2015 , 2014 , and 2013 . As of December 31, 2015 and 2014 , the balance in the Company's property damage reserve totaled approximately $38 million and $35 million , respectively, which is included in deferred liabilities in the balance sheets. When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. As authorized in the 2013 Rate Case Settlement Agreement, the Company may recover costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00 / 1,000 KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional details of the 2013 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 was zero at December 31, 2015 and had a balance of $4.0 million at December 31, 2014 . Included in current liabilities and deferred credits and other liabilities in the balance sheets at December 31, 2014 is $1.6 million and $2.4 million , respectively. The Company recorded a liability with a corresponding regulatory asset of $1.7 million for estimated liabilities related to outstanding claims and suits in excess of the reserve balance at December 31, 2015 , of which $1.6 million and $0.1 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. There were no liabilities in excess of the reserve balance at December 31, 2014 . Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities 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. See Note 10 for additional information regarding derivatives. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. |
Mississippi Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Mississippi Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. The Company is subject to regulation by the FERC and the Mississippi PSC. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers , revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $9 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Note 2 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid income taxes of $121 million with $105 million to non-current accumulated deferred income taxes and $16 million to other deferred charges in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. 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 $295 million , $259 million , and $205 million during 2015 , 2014 , and 2013 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $11 million , $13 million , and $13 million in 2015 , 2014 , and 2013 , respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, which were $8 million , $34 million , and $27 million in 2015 , 2014 , and 2013 , respectively. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, which totaled $27 million , $31 million , and $17 million in 2015 , 2014 , and 2013 , respectively. See Note 4 for additional information. The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015 , 2014 , or 2013 . The traditional operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans – regulatory assets $ 163 $ 169 (a,g) Property damage (64 ) (62 ) (i) Deferred income tax charges 291 227 (c) Remaining net book value of retired assets 36 2 (b) Property tax 27 28 (d) Vacation pay 11 11 (e,g) Plant Daniel Units 3 and 4 regulatory assets 29 23 (j) Other regulatory assets 16 18 (b) Fuel-hedging (realized and unrealized) losses 50 47 (f,g) Asset retirement obligations 70 11 (c) Other cost of removal obligations (167 ) (166 ) (c) Kemper IGCC regulatory assets 216 148 (h) Mirror CWIP — (271 ) (h) Other regulatory liabilities (11 ) (13 ) (b) Total regulatory assets (liabilities), net $ 667 $ 172 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (b) Recorded and recovered or amortized as approved by the Mississippi PSC. (c) Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (d) Recovered through the ad valorem tax adjustment clause over a 12 -month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. (e) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. (f) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM. (g) Not earning a return as offset in rate base by a corresponding asset or liability. (h) For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." (i) For additional information, see Note 1 under "Provision for Property Damage." (j) Deferred and amortized over a 10 -year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. 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 "Integrated Coal Gasification Combined Cycle" for additional information. Government Grants In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper IGCC through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants). Through December 31, 2015 , the Company has received grant funds of $245 million , used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs. An additional $25 million is expected to be received for its initial operation. See Note 3 under "Kemper IGCC Schedule and Cost Estimate" for additional information. Revenues Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually. The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.0% of the Company's total operating revenues in 2015 and are largely subject to rolling 10 -year cancellation 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 for the collection of the Company’s cost-based MRA electric tariff customers, the Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. See Note 3 under "Retail Regulatory Matters" for additional information. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. 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: 2015 2014 (in millions) Generation $ 2,723 $ 2,293 Transmission 688 665 Distribution 891 854 General 503 485 Plant acquisition adjustment 81 81 Total plant in service $ 4,886 $ 4,378 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for all costs associated with operating and maintaining the Kemper IGCC assets already placed in service and a portion of the railway track maintenance costs. The portion of railway track maintenance costs not charged to operation and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. Through second quarter 2015, all costs associated with the combined cycle and the associated common facilities portion of the Kemper IGCC, excluding the lignite mine, were deferred to a regulatory asset to be recovered over the life of the Kemper IGCC. Beginning in the third quarter 2015, the Company began expensing a portion of these ongoing cost previously deferred as regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. 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 4.7% in 2015 , 3.3% in 2014 , and 3.4% in 2013 . The increase in the 2015 depreciation rate is primarily due to an asset retirement obligation (ARO) at Plant Watson incurred as a result of changes in environmental regulations. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. On December 3, 2015, the Mississippi PSC approved the study filed in 2014, 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. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights is recognized and charged to fuel stock and is expected to be recovered through the Company’s fuel clause. Through the second quarter 2015, depreciation associated with the combined cycle and the associated common facilities portion of the Kemper IGCC was deferred as a regulatory asset to be recovered over the life of the Kemper IGCC. Beginning in the third quarter 2015, the Company began expensing certain ongoing project costs, including depreciation, that previously were deferred as regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" 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 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 on April 17, 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 the statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 48 $ 42 Liabilities incurred 101 — Liabilities settled (3 ) (3 ) Accretion 4 2 Cash flow revisions 27 7 Balance at end of year $ 177 $ 48 The increase in liabilities incurred and cash flow revisions in 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule located at Plant Watson and Plant Greene County. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The increase in cash flow revisions in 2014 related to the Company's AROs associated with the Plant Watson landfill and Plant Greene County asbestos. Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 5.99% , 6.91% , and 6.89% for the years ended December 31, 2015 , 2014 , and 2013 , respectively. AFUDC equity was $110 million , $136 million , and $122 million in 2015 , 2014 , and 2013 , respectively. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. Provision for Property Damage The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. In each of 2015 , 2014 , and 2013 , the Company made retail accruals of $3 million . The Company accrued $0.3 million annually in 2015 , 2014 , and 2013 for the wholesale jurisdiction. As of December 31, 2015 , the property damage reserve balances were $63 million and $1 million for retail and wholesale, respectively. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized. Fuel Inventory Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates or capitalized as part of the Kemper IGCC costs if used for testing. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the EPA are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities 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 qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel-hedging program as discussed below result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these would be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of operations. 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 does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income. Variable Interest Entities The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact |
Southern Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional operating companies, SCS, SouthernLINC Wireless, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Power Company and certain of its generation subsidiaries are subject to regulation by the FERC. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers (ASC 606) , revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On February 18, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02), which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015 and is not expected to result in any additional consolidation or deconsolidation of current entities. On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03) . ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $11 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 8 for disclosures impacted by ASU 2015-03. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $306 million and accrued income taxes of $2 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. Affiliate Transactions 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. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS amounted to approximately $146 million in 2015 , $126 million in 2014 , and $118 million in 2013 . Of these costs, approximately $138 million in 2015 , $125 million in 2014 , and $114 million in 2013 were charged to other operations and maintenance expenses; the remainder was 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. The Company has several agreements with SCS for transmission services. Transmission purchased from affiliates totaled $11 million in 2015 , $7 million in 2014 , and $8 million in 2013 . All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $219 million , $153 million , and $150 million in 2015 , 2014 , and 2013 , respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $109 million , $75 million , and $69 million in 2015 , 2014 , and 2013 , respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. Acquisition Accounting The Company acquires generation assets as part of its overall growth strategy. For acquisitions that meet the definition of a business, the Company includes the operations in its consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition is allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business are accounted for as asset acquisitions. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions are expensed as incurred. Revenues The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in operating 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. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. See "Financial Instruments" herein for additional information. Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the top three customers: 2015 2014 2013 Georgia Power 15.8 % 10.1 % 11.8 % FPL 10.7 % 9.7 % 10.7 % Duke Energy Corporation 8.2 % 9.1 % 10.3 % Fuel Costs Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Under current tax regulation, certain projects 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 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. 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 production tax credits (PTC), which are recorded to income tax expense based on production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during the year and will be carried forward and utilized in future years. The ITC carryforwards begin expiring in 2034, but are expected to be fully utilized by 2020. See Note 5 under "Effective Tax Rate" 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 The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost. 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. Depreciation Beginning in 2014, the Company changed to component depreciation, where the depreciation of the original cost of assets is computed principally by the straight-line method over the estimated useful lives of assets as determined by management. Certain generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. The primary assets in property, plant, and equipment are power plants, which have estimated useful lives ranging from 30 to 45 years . The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. Plant in service as of December 31, 2015 and 2014 that is depreciated on a units-of-production basis was approximately $485 million and $470 million , respectively. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized. Prior to 2014, the Company computed depreciation of the original cost of assets under the straight-line method and applied a composite depreciation rate based on the assets' estimated useful lives as determined by management. 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. The liability for AROs primarily relates to the Company's solar and wind facilities. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 13 $ 4 Liabilities incurred 7 8 Accretion 1 1 Balance at end of year $ 21 $ 13 Long-Term Service Agreements The Company has entered into LTSAs for the purpose of securing maintenance support for substantially all of its generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in noncurrent assets on the balance sheets and are recorded as payments pursuant to LTSAs in the statements of cash flows. All work performed is capitalized or charged to expense as appropriate based on the nature of the work when performed; therefore, these charges are non-cash and are not reflected in the statements of cash flows. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years . The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. The amortization expense for the acquired PPAs for each of the years ended December 31, 2015 , 2014 , and 2013 was $3 million , and is recorded in operating revenues. The amortization expense for future periods is as follows: Amortization Expense (in millions) 2016 $ 10 2017 17 2018 17 2019 17 2020 17 2021 and beyond 239 Total $ 317 Transmission Receivables/Prepayments As part of the Company's growth through the acquisition and construction of renewable facilities, the Company has transmission receivables and/or prepayments representing the reimbursable 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. Emission Reduction Credits The Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the EPA as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost and were $11 million at each of December 31, 2015 and 2014 . The cost of emission reduction offsets to be surrendered are generally transferred to CWIP upon commencement of the related construction. Restricted Cash The use of funds received under the credit facilities of RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC are restricted for construction purposes. The aggregate amount outstanding as of December 31, 2015 was $5 million and is included in other deferred charges and assets — non-affiliated. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. 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 does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income. Variable Interest Entities The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. |
Retirement Benefits
Retirement Benefits | 12 Months Ended |
Dec. 31, 2015 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016 . Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2016 , other postretirement trust contributions are expected to total approximately $14 million . 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.17 % 5.02 % 4.26 % Discount rate – service costs 4.48 5.02 4.26 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.04 % 4.85 % 4.05 % Discount rate – service costs 4.39 4.85 4.05 Expected long-term return on plan assets 6.97 7.15 7.13 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.67 % 4.17 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.51 % 4.04 % Annual salary increase 4.46 3.59 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension and other postretirement benefit plans by approximately $191 million and $35 million , respectively. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 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, 2015 as follows: 1 Percent 1 Percent (in millions) Benefit obligation $ 119 $ (102 ) Service and interest costs 4 (4 ) Pension Plans The total accumulated benefit obligation for the pension plans was $9.6 billion at December 31, 2015 and $10.0 billion at December 31, 2014 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 10,909 $ 8,863 Service cost 257 213 Interest cost 445 435 Benefits paid (487 ) (382 ) Actuarial loss (gain) (582 ) 1,780 Balance at end of year 10,542 10,909 Change in plan assets Fair value of plan assets at beginning of year 9,690 8,733 Actual return (loss) on plan assets (14 ) 797 Employer contributions 45 542 Benefits paid (487 ) (382 ) Fair value of plan assets at end of year 9,234 9,690 Accrued liability $ (1,308 ) $ (1,219 ) At December 31, 2015 , the projected benefit obligations for the qualified and non-qualified pension plans were $10.0 billion and $582 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 2,998 $ 3,073 Other current liabilities (46 ) (42 ) Employee benefit obligations (1,262 ) (1,177 ) Accumulated OCI 125 134 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2015 and 2014 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 2016 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2015: Accumulated OCI $ 3 $ 122 Regulatory assets 27 2,971 Total $ 30 $ 3,093 Balance at December 31, 2014: Accumulated OCI $ 4 $ 130 Regulatory assets 51 3,022 Total $ 55 $ 3,152 Estimated amortization in net periodic pension cost in 2016: Accumulated OCI $ 1 $ 6 Regulatory assets 13 145 Total $ 14 $ 151 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, 2015 and 2014 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2013 $ 64 $ 1,651 Net gain 75 1,552 Change in prior service costs — 1 Reclassification adjustments: Amortization of prior service costs (1 ) (25 ) Amortization of net gain (4 ) (106 ) Total reclassification adjustments (5 ) (131 ) Total change 70 1,422 Balance at December 31, 2014 $ 134 $ 3,073 Net loss 1 155 Reclassification adjustments: Amortization of prior service costs (1 ) (24 ) Amortization of net gain (9 ) (206 ) Total reclassification adjustments (10 ) (230 ) Total change (9 ) (75 ) Balance at December 31, 2015 $ 125 $ 2,998 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 257 $ 213 $ 232 Interest cost 445 435 389 Expected return on plan assets (724 ) (645 ) (603 ) Recognized net loss 215 110 200 Net amortization 25 26 27 Net periodic pension cost $ 218 $ 139 $ 245 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, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 450 2017 478 2018 501 2019 527 2020 554 2021 to 2025 3,141 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 1,986 $ 1,682 Service cost 23 21 Interest cost 78 79 Benefits paid (102 ) (102 ) Actuarial loss (gain) (38 ) 300 Plan amendments 34 (2 ) Retiree drug subsidy 8 8 Balance at end of year 1,989 1,986 Change in plan assets Fair value of plan assets at beginning of year 900 901 Actual return (loss) on plan assets (12 ) 54 Employer contributions 39 39 Benefits paid (94 ) (94 ) Fair value of plan assets at end of year 833 900 Accrued liability $ (1,156 ) $ (1,086 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 433 $ 387 Other current liabilities (4 ) (4 ) Employee benefit obligations (1,152 ) (1,082 ) Other regulatory liabilities, deferred (22 ) (21 ) Accumulated OCI 8 8 Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2015 and 2014 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 2016 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2015: Accumulated OCI $ — $ 8 Net regulatory assets 32 379 Total $ 32 $ 387 Balance at December 31, 2014: Accumulated OCI $ — $ 8 Net regulatory assets 2 364 Total $ 2 $ 372 Estimated amortization as net periodic postretirement benefit cost in 2016: Net regulatory assets $ 6 $ 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, 2015 and 2014 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2013 $ 1 $ 73 Net gain 7 301 Change in prior service costs — (2 ) Reclassification adjustments: Amortization of prior service costs — (4 ) Amortization of net gain — (2 ) Total reclassification adjustments — (6 ) Total change 7 293 Balance at December 31, 2014 $ 8 $ 366 Net gain — 33 Change in prior service costs — 33 Reclassification adjustments: Amortization of prior service costs — (4 ) Amortization of net gain — (17 ) Total reclassification adjustments — (21 ) Total change — 45 Balance at December 31, 2015 $ 8 $ 411 Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 23 $ 21 $ 24 Interest cost 78 79 74 Expected return on plan assets (58 ) (59 ) (56 ) Net amortization 21 6 21 Net periodic postretirement benefit cost $ 64 $ 47 $ 63 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) 2016 $ 123 $ (9 ) $ 114 2017 128 (10 ) 118 2018 133 (11 ) 122 2019 137 (12 ) 125 2020 139 (12 ) 127 2021 to 2025 711 (65 ) 646 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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 42 % 38 % 41 % International equity 21 23 23 Domestic fixed income 24 26 26 Global fixed income 4 4 3 Special situations 1 1 — Real estate investments 5 6 5 Private equity 3 2 2 Total 100 % 100 % 100 % The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2015 and 2014 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. • Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 1,632 $ 681 $ — $ — $ 2,313 International equity* 1,190 990 — — 2,180 Fixed income: U.S. Treasury, government, and agency bonds — 454 — — 454 Mortgage- and asset-backed securities — 199 — — 199 Corporate bonds — 1,140 — — 1,140 Pooled funds — 500 — — 500 Cash equivalents and other — 145 — — 145 Real estate investments 299 — — 1,218 1,517 Private equity — — — 635 635 Total $ 3,121 $ 4,109 $ — $ 1,853 $ 9,083 Liabilities: Derivatives $ (1 ) $ — $ — $ — $ (1 ) Total $ 3,120 $ 4,109 $ — $ 1,853 $ 9,082 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 1,704 $ 704 $ — $ — $ 2,408 International equity* 1,070 986 — — 2,056 Fixed income: U.S. Treasury, government, and agency bonds — 699 — — 699 Mortgage- and asset-backed securities — 188 — — 188 Corporate bonds — 1,135 — — 1,135 Pooled funds — 514 — — 514 Cash equivalents and other 3 660 — — 663 Real estate investments 293 — — 1,121 1,414 Private equity — — — 570 570 Total $ 3,070 $ 4,886 $ — $ 1,691 $ 9,647 Liabilities: Derivatives $ (2 ) $ — $ — $ — $ (2 ) Total $ 3,068 $ 4,886 $ — $ 1,691 $ 9,645 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Total As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity* $ 106 $ 52 $ — $ — $ 158 International equity* 40 64 — — 104 Fixed income: U.S. Treasury, government, and agency bonds — 22 — — 22 Mortgage- and asset-backed securities — 7 — — 7 Corporate bonds — 38 — — 38 Pooled funds — 42 — — 42 Cash equivalents and other 11 9 — — 20 Trust-owned life insurance — 370 — — 370 Real estate investments 11 — — 41 52 Private equity — — — 21 21 Total $ 168 $ 604 $ — $ 62 $ 834 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 147 $ 56 $ — $ — $ 203 International equity* 36 67 — — 103 Fixed income: U.S. Treasury, government, and agency bonds — 29 — — 29 Mortgage- and asset-backed securities — 6 — — 6 Corporate bonds — 39 — — 39 Pooled funds — 41 — — 41 Cash equivalents and other 9 27 — — 36 Trust-owned life insurance — 381 — — 381 Real estate investments 11 — — 37 48 Private equity — — — 19 19 Total $ 203 $ 646 $ — $ 56 $ 905 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Employee Savings Plan Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015 , 2014 , and 2013 were $92 million , $87 million , and $84 million , respectively. |
Alabama Power [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016 . 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, 2016 , 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.18 % 5.02 % 4.27 % Discount rate – service costs 4.49 5.02 4.27 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.04 % 4.86 % 4.06 % Discount rate – service costs 4.40 4.86 4.06 Expected long-term return on plan assets 7.17 7.34 7.36 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.67 % 4.18 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.51 % 4.04 % Annual salary increase 4.46 3.59 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $51 million and $9 million , respectively. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 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, 2015 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 29 $ (25 ) Service and interest costs 1 (1 ) Pension Plans The total accumulated benefit obligation for the pension plans was $2.3 billion at December 31, 2015 and $2.4 billion at December 31, 2014 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,592 $ 2,112 Service cost 59 48 Interest cost 106 103 Benefits paid (120 ) (100 ) Actuarial loss (gain) (131 ) 429 Balance at end of year 2,506 2,592 Change in plan assets Fair value of plan assets at beginning of year 2,396 2,278 Actual return (loss) on plan assets (9 ) 207 Employer contributions 12 11 Benefits paid (120 ) (100 ) Fair value of plan assets at end of year 2,279 2,396 Accrued liability $ (227 ) $ (196 ) At December 31, 2015 , the projected benefit obligations for the qualified and non-qualified pension plans were $2.4 billion and $124 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 822 $ 827 Other current liabilities (11 ) (10 ) Employee benefit obligations (216 ) (186 ) Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 6 $ 12 $ 3 Net (gain) loss 816 815 40 Regulatory assets $ 822 $ 827 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 827 $ 476 Net (gain) loss 56 389 Reclassification adjustments: Amortization of prior service costs (6 ) (7 ) Amortization of net gain (loss) (55 ) (31 ) Total reclassification adjustments (61 ) (38 ) Total change (5 ) 351 Ending balance $ 822 $ 827 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 59 $ 48 $ 52 Interest cost 106 103 93 Expected return on plan assets (178 ) (168 ) (157 ) Recognized net loss 55 31 52 Net amortization 6 7 7 Net periodic pension cost $ 48 $ 21 $ 47 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, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 114 2017 119 2018 124 2019 129 2020 134 2021 to 2025 740 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 503 $ 431 Service cost 6 5 Interest cost 20 20 Benefits paid (27 ) (27 ) Actuarial loss (gain) (7 ) 71 Plan amendment 7 — Retiree drug subsidy 3 3 Balance at end of year 505 503 Change in plan assets Fair value of plan assets at beginning of year 392 389 Actual return (loss) on plan assets (6 ) 23 Employer contributions 1 4 Benefits paid (24 ) (24 ) Fair value of plan assets at end of year 363 392 Accrued liability $ (142 ) $ (111 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 95 $ 68 Other regulatory liabilities, deferred (13 ) (14 ) Employee benefit obligations (142 ) (111 ) Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 19 $ 15 $ 4 Net (gain) loss 63 39 2 Net regulatory assets $ 82 $ 54 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Net regulatory assets (liabilities): Beginning balance $ 54 $ (15 ) Net (gain) loss 25 73 Change in prior service costs 8 — Reclassification adjustments: Amortization of prior service costs (3 ) (4 ) Amortization of net gain (loss) (2 ) — Total reclassification adjustments (5 ) (4 ) Total change 28 69 Ending balance $ 82 $ 54 Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 6 $ 5 $ 6 Interest cost 20 20 19 Expected return on plan assets (26 ) (25 ) (23 ) Net amortization 5 4 5 Net periodic postretirement benefit cost $ 5 $ 4 $ 7 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) 2016 $ 33 $ (3 ) $ 30 2017 34 (3 ) 31 2018 34 (3 ) 31 2019 35 (4 ) 31 2020 36 (4 ) 32 2021 to 2025 184 (20 ) 164 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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 48 % 45 % 48 % International equity 20 20 20 Domestic fixed income 24 27 26 Special situations 1 1 — Real estate investments 4 5 4 Private equity 3 2 2 Total 100 % 100 % 100 % The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2015 and 2014 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. • Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 403 $ 168 $ — $ — $ 571 International equity* 294 244 — — 538 Fixed income: U.S. Treasury, government, and agency bonds — 112 — — 112 Mortgage- and asset-backed securities — 49 — — 49 Corporate bonds — 280 — — 280 Pooled funds — 123 — — 123 Cash equivalents and other — 36 — — 36 Real estate investments 74 — — 301 375 Private equity — — — 157 157 Total $ 771 $ 1,012 $ — $ 458 $ 2,241 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 421 $ 174 $ — $ — $ 595 International equity* 264 244 — — 508 Fixed income: U.S. Treasury, government, and agency bonds — 173 — — 173 Mortgage- and asset-backed securities — 47 — — 47 Corporate bonds — 280 — — 280 Pooled funds — 127 — — 127 Cash equivalents and other 1 163 — — 164 Real estate investments 73 — — 277 350 Private equity — — — 141 141 Total $ 759 $ 1,208 $ — $ 418 $ 2,385 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 57 $ 8 $ — $ — $ 65 International equity* 14 12 — — 26 Fixed income: U.S. Treasury, government, and agency bonds — 8 — — 8 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 13 — — 13 Pooled funds — 6 — — 6 Cash equivalents and other 1 2 — — 3 Trust-owned life insurance — 212 — — 212 Real estate investments 5 — — 14 19 Private equity — — — 7 7 Total $ 77 $ 263 $ — $ 21 $ 361 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 76 $ 8 $ — $ — $ 84 International equity* 13 12 — — 25 Fixed income: U.S. Treasury, government, and agency bonds — 10 — — 10 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 14 — — 14 Pooled funds — 6 — — 6 Cash equivalents and other — 8 — — 8 Trust-owned life insurance — 217 — — 217 Real estate investments 5 — — 13 18 Private equity — — — 7 7 Total $ 94 $ 277 $ — $ 20 $ 391 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015 , 2014 , and 2013 were $22 million , $21 million , and $20 million , respectively. |
Georgia Power [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016 . 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, 2016 , other postretirement trust contributions are expected to total approximately $14 million . 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: 2015 2014 2013 Pension plans Discount rates – interest costs 4.18 % 5.02 % 4.27 % Discount rates – service costs 4.49 5.02 4.27 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.03 % 4.85 % 4.04 % Discount rate – service costs 4.39 4.85 4.04 Expected long-term return on plan assets 6.48 6.75 6.74 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.65 % 4.18 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.49 % 4.03 % Annual salary increase 4.46 3.59 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $66 million and $17 million , respectively. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 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, 2015 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 58 $ (50 ) Service and interest costs 2 (2 ) Pension Plans The total accumulated benefit obligation for the pension plans was $3.3 billion at December 31, 2015 and $3.5 billion at December 31, 2014 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 3,781 $ 3,116 Service cost 73 62 Interest cost 154 153 Benefits paid (188 ) (149 ) Actuarial loss (gain) (205 ) 599 Balance at end of year 3,615 3,781 Change in plan assets Fair value of plan assets at beginning of year 3,383 3,085 Actual return (loss) on plan assets (13 ) 285 Employer contributions 14 162 Benefits paid (188 ) (149 ) Fair value of plan assets at end of year 3,196 3,383 Accrued liability $ (419 ) $ (398 ) At December 31, 2015 , the projected benefit obligations for the qualified and non-qualified pension plans were $3.5 billion and $151 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 1,076 $ 1,102 Current liabilities, other (13 ) (12 ) Employee benefit obligations (406 ) (386 ) Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 8 $ 17 $ 5 Net (gain) loss 1,068 1,085 55 Regulatory assets $ 1,076 $ 1,102 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 1,102 $ 610 Net (gain) loss 59 543 Reclassification adjustments: Amortization of prior service costs (9 ) (10 ) Amortization of net gain (loss) (76 ) (41 ) Total reclassification adjustments (85 ) (51 ) Total change (26 ) 492 Ending balance $ 1,076 $ 1,102 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 73 $ 62 $ 69 Interest cost 154 153 138 Expected return on plan assets (251 ) (228 ) (212 ) Recognized net loss 76 41 74 Net amortization 9 10 10 Net periodic pension cost $ 61 $ 38 $ 79 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, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 168 2017 176 2018 183 2019 189 2020 197 2021 to 2025 1,085 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 864 $ 723 Service cost 7 6 Interest cost 34 34 Benefits paid (45 ) (44 ) Actuarial loss (gain) (22 ) 142 Plan amendment 12 — Retiree drug subsidy 4 3 Balance at end of year 854 864 Change in plan assets Fair value of plan assets at beginning of year 395 407 Actual return (loss) on plan assets (6 ) 21 Employer contributions 10 8 Benefits paid (41 ) (41 ) Fair value of plan assets at end of year 358 395 Accrued liability $ (496 ) $ (469 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 223 $ 213 Employee benefit obligations (496 ) (469 ) Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 8 $ (5 ) $ 1 Net (gain) loss 215 218 9 Regulatory assets $ 223 $ 213 The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 213 $ 69 Net (gain) loss 9 146 Change in prior service costs 12 — Reclassification adjustments: Amortization of net gain (loss) (11 ) (2 ) Total change 10 144 Ending balance $ 223 $ 213 Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 7 $ 6 $ 7 Interest cost 34 34 31 Expected return on plan assets (24 ) (25 ) (24 ) Net amortization 11 2 12 Net periodic postretirement benefit cost $ 28 $ 17 $ 26 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) 2016 $ 53 $ (4 ) $ 49 2017 55 (4 ) 51 2018 58 (5 ) 53 2019 59 (5 ) 54 2020 60 (5 ) 55 2021 to 2025 305 (28 ) 277 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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 40 % 34 % 38 % International equity 21 27 26 Domestic fixed income 23 25 24 Global fixed income 9 8 7 Special situations 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. 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, 2015 and 2014 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. • Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 565 $ 236 $ — $ — $ 801 International equity* 412 343 — — 755 Fixed income: U.S. Treasury, government, and agency bonds — 157 — — 157 Mortgage- and asset-backed securities — 69 — — 69 Corporate bonds — 394 — — 394 Pooled funds — 173 — — 173 Cash equivalents and other — 50 — — 50 Real estate investments 103 — — 421 524 Private equity — — — 220 220 Total $ 1,080 $ 1,422 $ — $ 641 $ 3,143 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 595 $ 246 $ — $ — $ 841 International equity* 373 344 — — 717 Fixed income: U.S. Treasury, government, and agency bonds — 244 — — 244 Mortgage- and asset-backed securities — 66 — — 66 Corporate bonds — 398 — — 398 Pooled funds — 179 — — 179 Cash equivalents and other 1 230 — — 231 Real estate investments 102 — — 391 493 Private equity — — — 199 199 Total $ 1,071 $ 1,707 $ — $ 590 $ 3,368 Liabilities: Derivatives $ (1 ) $ — $ — $ — $ (1 ) Total $ 1,070 $ 1,707 $ — $ 590 $ 3,367 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 30 $ 36 $ — $ — $ 66 International equity* 12 41 — — 53 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 12 — — 12 Pooled funds — 30 — — 30 Cash equivalents and other 10 6 — — 16 Trust-owned life insurance — 158 — — 158 Real estate investments 3 — — 12 15 Private equity — — — 7 7 Total $ 55 $ 290 $ — $ 19 $ 364 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 53 $ 40 $ — $ — $ 93 International equity* 11 45 — — 56 Fixed income: U.S. Treasury, government, and agency bonds — 7 — — 7 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 12 — — 12 Pooled funds — 29 — — 29 Cash equivalents and other 8 11 — — 19 Trust-owned life insurance — 162 — — 162 Real estate investments 3 — — 12 15 Private equity — — — 6 6 Total $ 75 $ 308 $ — $ 18 $ 401 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015 , 2014 , and 2013 were $26 million , $25 million , and $24 million , respectively. |
Gulf Power [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016 . 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, 2016 , 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.18 % 5.02 % 4.27 % Discount rate – service costs 4.48 5.02 4.27 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.04 % 4.86 % 4.06 % Discount rate – service costs 4.38 4.86 4.06 Expected long-term return on plan assets 8.07 8.08 8.04 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.71 % 4.18 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.51 % 4.04 % Annual salary increase 4.46 3.59 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $9 million and $1 million , respectively. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 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, 2015 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 $424 million at December 31, 2015 and $438 million at December 31, 2014 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 491 $ 395 Service cost 12 10 Interest cost 20 19 Benefits paid (20 ) (16 ) Actuarial loss (gain) (23 ) 83 Balance at end of year 480 491 Change in plan assets Fair value of plan assets at beginning of year 435 386 Actual return on plan assets 4 34 Employer contributions 1 31 Benefits paid (20 ) (16 ) Fair value of plan assets at end of year 420 435 Accrued liability $ (60 ) $ (56 ) At December 31, 2015 , the projected benefit obligations for the qualified and non-qualified pension plans were $457 million and $23 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 142 $ 146 Current liabilities, other (1 ) (1 ) Employee benefit obligations (59 ) (55 ) Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 2 $ 3 $ 1 Net loss 140 143 6 Regulatory assets $ 142 $ 146 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 146 $ 75 Net (gain) loss 6 77 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (9 ) (5 ) Total reclassification adjustments (10 ) (6 ) Total change (4 ) 71 Ending balance $ 142 $ 146 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 12 $ 10 $ 11 Interest cost 20 19 17 Expected return on plan assets (32 ) (28 ) (26 ) Recognized net loss 9 5 9 Net amortization 1 1 1 Net periodic pension cost $ 10 $ 7 $ 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, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 19 2017 20 2018 21 2019 22 2020 24 2021 to 2025 139 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 78 $ 69 Service cost 1 1 Interest cost 3 3 Benefits paid (4 ) (4 ) Actuarial loss (gain) (1 ) 11 Plan amendment 4 (2 ) Retiree drug subsidy — — Balance at end of year 81 78 Change in plan assets Fair value of plan assets at beginning of year 18 17 Actual return on plan assets — 2 Employer contributions 3 3 Benefits paid (4 ) (4 ) Fair value of plan assets at end of year 17 18 Accrued liability $ (64 ) $ (60 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 10 $ 6 Current liabilities, other (1 ) (1 ) Other regulatory liabilities, deferred (5 ) (4 ) Employee benefit obligations (63 ) (59 ) Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ — $ (2 ) $ — Net loss 5 4 — Net regulatory assets (liabilities) $ 5 $ 2 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Net regulatory assets (liabilities): Beginning balance $ 2 $ (7 ) Net (gain) loss 1 11 Change in prior service costs 2 (2 ) Reclassification adjustments: Amortization of prior service costs — — Amortization of net gain (loss) — — Total reclassification adjustments — — Total change 3 9 Ending balance $ 5 $ 2 Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (1 ) (1 ) (1 ) Net amortization — — — 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) 2016 $ 5 $ — $ 5 2017 5 — 5 2018 6 — 6 2019 6 (1 ) 5 2020 6 (1 ) 5 2021 to 2025 29 (3 ) 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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 25 % 29 % 29 % International equity 24 22 22 Domestic fixed income 25 25 29 Special situations 3 2 1 Real estate investments 14 16 14 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. 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, 2015 and 2014 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 73 $ 31 $ — $ — $ 104 International equity* 54 45 — — 99 Fixed income: U.S. Treasury, government, and agency bonds — 21 — — 21 Mortgage- and asset-backed securities — 9 — — 9 Corporate bonds — 51 — — 51 Pooled funds — 23 — — 23 Cash equivalents and other — 7 — — 7 Real estate investments 14 — — 55 69 Private equity — — — 29 29 Total $ 141 $ 187 $ — $ 84 $ 412 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 77 $ 32 $ — $ — $ 109 International equity* 48 44 — — 92 Fixed income: U.S. Treasury, government, and agency bonds — 31 — — 31 Mortgage- and asset-backed securities — 8 — — 8 Corporate bonds — 51 — — 51 Pooled funds — 23 — — 23 Cash equivalents and other — 30 — — 30 Real estate investments 13 — — 50 63 Private equity — — — 26 26 Total $ 138 $ 219 $ — $ 76 $ 433 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 3 $ 1 $ — $ — $ 4 International equity* 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Mortgage- and asset-backed securities — — — — — 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 $ 7 $ 7 $ — $ 3 $ 17 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 3 $ 1 $ — $ — $ 4 International equity* 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Mortgage- and asset-backed securities — 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 $ 6 $ 9 $ — $ 3 $ 18 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015 , 2014 , and 2013 were $4 million each year. |
Mississippi Power [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
RETIREMENT BENEFITS | RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016 . 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, 2016 , 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.17 % 5.01 % 4.26 % Discount rate – service costs 4.49 5.01 4.26 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.03 % 4.85 % 4.04 % Discount rate – service costs 4.38 4.85 4.04 Expected long-term return on plan assets 7.23 7.30 7.04 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.69 % 4.17 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.47 % 4.03 % Annual salary increase 4.46 3.59 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension and other postretirement benefit plans by approximately $9 million and $2 million , respectively. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 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, 2015 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 $447 million at December 31, 2015 and $462 million at December 31, 2014 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 513 $ 409 Service cost 13 10 Interest cost 21 20 Benefits paid (22 ) (17 ) Actuarial loss (gain) (25 ) 91 Balance at end of year 500 513 Change in plan assets Fair value of plan assets at beginning of year 446 387 Actual return on plan assets 4 40 Employer contributions 2 36 Benefits paid (22 ) (17 ) Fair value of plan assets at end of year 430 446 Accrued liability $ (70 ) $ (67 ) At December 31, 2015 , the projected benefit obligations for the qualified and non-qualified pension plans were $470 million and $30 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 144 $ 151 Other current liabilities (3 ) (2 ) Employee benefit obligations (67 ) (65 ) Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 2 $ 3 $ 1 Net loss 142 148 7 Regulatory assets $ 144 $ 151 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 151 $ 78 Net (gain) loss 4 79 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (10 ) (5 ) Total reclassification adjustments (11 ) (6 ) Total change (7 ) 73 Ending balance $ 144 $ 151 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 13 $ 10 $ 11 Interest cost 21 20 18 Expected return on plan assets (33 ) (29 ) (27 ) Recognized net loss 10 5 10 Net amortization 1 1 1 Net periodic pension cost $ 12 $ 7 $ 13 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, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 20 2017 21 2018 22 2019 24 2020 25 2021 to 2025 146 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 96 $ 81 Service cost 1 1 Interest cost 4 4 Benefits paid (5 ) (5 ) Actuarial loss (gain) (1 ) 14 Plan amendment 1 — Retiree drug subsidy 1 1 Balance at end of year 97 96 Change in plan assets Fair value of plan assets at beginning of year 24 23 Actual return on plan assets — 2 Employer contributions 3 3 Benefits paid (4 ) (4 ) Fair value of plan assets at end of year 23 24 Accrued liability $ (74 ) $ (72 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 21 $ 18 Other regulatory liabilities, deferred (3 ) (2 ) Employee benefit obligations (74 ) (72 ) Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ — $ (2 ) $ — Net (gain) loss (18 ) 18 1 Net regulatory assets $ (18 ) $ 16 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Net regulatory assets (liabilities): Beginning balance $ 16 $ 2 Net (gain) loss — 14 Change in prior service costs 3 — Reclassification adjustments: Amortization of net gain (loss) (1 ) — Total reclassification adjustments (1 ) — Total change 2 14 Ending balance $ 18 $ 16 Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 4 4 4 Expected return on plan assets (2 ) (2 ) (1 ) Net amortization 1 — — Net periodic postretirement benefit cost $ 4 $ 3 $ 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) 2016 $ 6 $ — $ 6 2017 6 (1 ) 5 2018 6 (1 ) 5 2019 7 (1 ) 6 2020 7 (1 ) 6 2021 to 2025 36 (2 ) 34 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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 21 % 24 % 24 % International equity 20 18 19 Domestic fixed income 38 38 41 Special situations 3 2 1 Real estate investments 11 13 11 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. 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, 2015 and 2014 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 76 $ 32 $ — $ — $ 108 International equity* 55 46 — — 101 Fixed income: U.S. Treasury, government, and agency bonds — 21 — — 21 Mortgage- and asset-backed securities — 9 — — 9 Corporate bonds — 53 — — 53 Pooled funds — 23 — — 23 Cash equivalents and other — 7 — — 7 Real estate investments 14 — — 57 71 Private equity — — — 30 30 Total $ 145 $ 191 $ — $ 87 $ 423 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 78 $ 32 $ — $ — $ 110 International equity* 49 45 — — 94 Fixed income: U.S. Treasury, government, and agency bonds — 32 — — 32 Mortgage- and asset-backed securities — 9 — — 9 Corporate bonds — 53 — — 53 Pooled funds — 24 — — 24 Cash equivalents and other — 30 — — 30 Real estate investments 14 — — 51 65 Private equity — — — 26 26 Total $ 141 $ 225 $ — $ 77 $ 443 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 3 $ 1 $ — $ — $ 4 International equity* 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 6 — — 6 Mortgage- and asset-backed securities — — — — — Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 — — — 1 Real estate investments 1 — — 3 4 Private equity — — — 1 1 Total $ 7 $ 12 $ — $ 4 $ 23 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (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 — 6 — — 6 Mortgage- and asset-backed securities — — — — — Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 1 — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 7 $ 14 $ — $ 3 $ 24 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015 , 2014 , and 2013 were $5 million , $5 million , and $4 million , respectively. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition [Line Items] | |
ACQUISITIONS | 12. ACQUISITIONS Southern Company Proposed Merger with AGL Resources On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company. Upon the consummation of the Merger, each share of common stock of AGL Resources issued and outstanding immediately prior to the effective time of the Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and any shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes (Merger Consideration). Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement. In accordance with GAAP, the Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill. Southern Company expects total cash of $8.2 billion to be required to fund the purchase price of approximately $8.0 billion to acquire AGL Resources common stock, options to purchase shares of AGL Resources common stock, and restricted stock units payable in shares of AGL Resources common stock and to fund acquisition-related expenses and financing costs of approximately $200 million . Southern Company will also assume AGL Resources' outstanding indebtedness. The Merger was approved by AGL Resources' shareholders on November 19, 2015, and the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired on December 4, 2015. Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, and New Jersey Board of Public Utilities, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company completed the required state regulatory applications in the fourth quarter 2015 and the required FCC filings in February 2016. On February 24, 2016, a stipulation and settlement agreement between Southern Company, AGL Resources, the Maryland PSC Staff, and the Maryland Office of People's Counsel was filed with the Maryland PSC. The proposed settlement remains subject to the approval of the Maryland PSC. Additionally, Southern Company received the approval of the Virginia State Corporation Commission in February 2016. Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources will be required to pay Southern Company a termination fee of $201 million or reimburse Southern Company's expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the transaction in the second half of 2016. During 2015, the Company incurred external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $41 million . The ultimate outcome of these matters cannot be determined at this time. Merger Financing Southern Company intends to initially fund the cash consideration for the Merger using a mix of debt and equity. Southern Company expects to issue the debt to fund the Merger Consideration in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See Note 6 under "Bank Credit Arrangements" for additional information regarding the Bridge Agreement. Proposed Acquisition of PowerSecure International, Inc. (Unaudited) On February 24, 2016, Southern Company entered into an Agreement and Plan of Merger to acquire PowerSecure International, Inc. Under the terms of this merger agreement, the stockholders of PowerSecure International, Inc. will be entitled to receive $18.75 in cash for each share of common stock in a transaction with a total purchase price of approximately $431 million . Following this transaction, PowerSecure International, Inc. will become a wholly-owned subsidiary of Southern Company. This transaction is expected to close by the end of the second quarter 2016, subject to, among other items, approval by PowerSecure International, Inc. stockholders and notification, clearance, and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Power During 2015 and 2014, in accordance with Southern Power's overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc. (SRE), the projects set forth in the following table. Acquisition-related costs of approximately $4 million were expensed as incurred. The acquisitions do not include any contingent consideration unless specifically noted. 2015 Project Facility Seller; Acquisition Date Approx. Location Southern Power Percentage Ownership Expected/Actual COD PPA for Plant Output PPA Approx. Purchase Price (MW) (in millions) WIND Kay Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 12, 2015 Westar Energy, Inc. and Grant River Dam Authority 20 years $ 481 (b) Grant Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % March 2016 Western Farmers, East Texas, and Northeast Texas Electric Cooperative 20 years $ 258 (c) SOLAR Lost Hills Blackwell First Solar, Inc. (First Solar) 33 Kern County, CA 51 % (a) April 17, 2015 City of Roseville, California/Pacific Gas and Electric Company 29 years $ 73 (d) North Star First Solar 61 Fresno County, CA 51 % (a) June 20, 2015 Pacific Gas and Electric Company 20 years $ 208 (e) Tranquillity Recurrent Energy, LLC 205 Fresno County, CA 51 % (a) Fourth quarter 2016 Shell Energy North America (US), LP and then Southern California Edison (SCE) 18 years $ 100 (f) Desert Stateline First Solar 299 San Bernardino County, CA 51 % (a) From December 2015 to third quarter 2016 (h) SCE 20 years $ 439 (g) Morelos Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % November 25, 2015 Pacific Gas and Electric Company 20 years $ 45 (i) Roserock Recurrent Energy, LLC 160 Pecos County, TX 51 % (a) Fourth quarter 2016 Austin Energy 20 years $ 45 (j) Garland and Garland A Recurrent Energy, LLC 205 Kern County, CA 51 % (a) Fourth quarter 2016 SCE 15 years $ 49 (k) Calipatria Solar Frontier Americas Holding, LLC 20 Imperial County, CA 90 % February 11, 2016 San Diego Gas & Electric Company 20 years $ 52 (l) (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. At each acquisition, Southern Power acquired a controlling interest in the entity owning the project facility and recorded approximately $227 million for the noncontrolling interests, in the aggregate, which is recorded as a non-cash transaction in contributions from noncontrolling interests and plant acquisitions. (b) Kay Wind - The total purchase price, including $35 million of contingent consideration, is approximately $481 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $481 million as CWIP, $8 million as a receivable related to transmission interconnection costs, and $8 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. (c) Grant Wind - On September 4, 2015, Southern Power entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at or near the expected COD. The purchase price includes approximately $24 million of contingent consideration and may be adjusted based on performance testing and production over the first 10 years of operation. The ultimate outcome of this matter cannot be determined at this time. (d) Lost Hills Blackwell - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $34 million . At the acquisition date, the members became contingently obligated to pay $3 million of construction payables through COD, making the aggregate purchase price approximately $107 million . The fair values of the assets acquired through the business combination were recorded as follows: $105 million as property, plant, and equipment, $3 million as a receivable related to transmission interconnection costs, and $4 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. (e) North Star - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $99 million . At the acquisition date, the members became contingently obligated to pay $233 million of construction payables through COD, making the aggregate purchase price approximately $307 million . The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $25 million as an intangible asset, $21 million as a receivable related to transmission interconnection costs, and $238 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The amortization expense for the year ended December 31, 2015 was $1 million . The estimated amortization for future periods is approximately $1.2 million per year for 2016 through 2020, and $18 million thereafter. (f) Tranquillity - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $173 million of assets and receiving an initial distribution of $100 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $186 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million . The ultimate outcome of this matter cannot be determined at this time. (g) Desert Stateline - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million . As of December 31, 2015, the fair values of the assets acquired through the business combination, which includes Southern Power's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion . The ultimate outcome of this matter cannot be determined at this time. (h) Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service. (i) Morelos - The total purchase price, including the minority owner, Turner Renewable Energy, LLC's (TRE) 10% ownership interest, is approximately $50 million . As of December 31, 2015, the fair values of the assets acquired through the business combination were recorded as follows: $49 million as property, plant, and equipment and $1 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. (j) Roserock - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $26 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $75 million as CWIP, $6 million as other receivables, and $10 million as payables and accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million . The ultimate outcome of this matter cannot be determined at this time. (k) Garland and Garland A - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $31 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $107 million as CWIP, $1 million as other deferred assets, and $28 million as payables and other accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million . The ultimate outcome of this matter cannot be determined at this time. (l) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $58 million . 2014 Project Seller; Acquisition Date Approx. Nameplate Capacity Location Southern Power Percentage Ownership COD PPA PPA Contract Period Approx. Purchase Price (MW) (in millions) SOLAR Adobe Sun Edison, LLC 20 Kern County, CA 90 % May 21, 2014 SCE 20 years $ 86 (b) Macho Springs First Solar Development, LLC 50 Luna County, NM 90 % May 23, 2014 El Paso Electric Company 20 years $ 117 (c) Imperial Valley First Solar, October 22, 2014 150 Imperial County, CA 51 % (a) November 26, 2014 San Diego Gas & Electric Company 25 years $ 505 (d) (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) Adobe - Total purchase price, including the minority owner TRE's 10% ownership interest, was $97 million . The fair values of the assets acquired were ultimately recorded as follows: $84 million to property, plant, and equipment, $15 million to prepayment related to transmission services, and $6 million to PPA intangible, resulting in a $5 million bargain purchase gain and a $3 million deferred tax liability. The bargain purchase gain is included in other income (expense), net. Acquisition-related costs were expensed as incurred and were not material. (c) Macho Springs - Total purchase price, including the minority owner TRE's 10% ownership interest, was $130 million . The fair values of the assets acquired were ultimately recorded as follows: $128 million to property, plant, and equipment, $1 million to prepaid property taxes, and $1 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material. (d) Imperial Valley - In connection with this acquisition, SG2 Holdings, LLC (SG2 Holdings) made an aggregate payment of approximately $128 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599 million upon completion of the facility (representing the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved in November 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by Southern Power for the acquisition of Imperial Valley was approximately $505 million in addition to the $223 million noncash contribution by the minority member. The fair values of the assets acquired were ultimately recorded as follows: $708 million to property, plant, and equipment and $20 million to prepayment related to transmission services. Acquisition-related costs were expensed as incurred and were not material. Construction Projects During 2015, in accordance with Southern Power's overall growth strategy, Southern Power constructed or commenced construction of the projects set forth in the table below, in addition to the Tranquillity, Desert Stateline, Roserock, Garland, and Garland A facilities. Total cost of construction incurred for these projects during 2015 was $1.8 billion , of which $1.1 billion remains in CWIP at December 31, 2015 . Solar Facility Seller Approx. Nameplate Capacity County Location in Georgia Expected/Actual COD PPA Counterparties PPA Contract Period Estimated Construction Cost (MW) (in millions) Sandhills N/A 146 Taylor Fourth quarter 2016 Cobb, Flint, and Sawnee Electric Membership Corporations 25 years $ 260 - 280 Decatur Parkway TradeWind Energy, Inc. 84 Decatur December 31, 2015 Georgia Power (a) 25 years Approx. $169 (c) Decatur County TradeWind Energy, Inc. 20 Decatur December 29, 2015 Georgia Power 20 years Approx. $46 (c) Butler CERSM, LLC and Community Energy, Inc. 103 Taylor Fourth quarter 2016 Georgia Power (b) 30 years $ 220 - 230 (c) Pawpaw Longview Solar, LLC 30 Taylor March 2016 Georgia Power (a) 30 years $ 70 - 80 (c) Butler Solar Farm Strata Solar Development, LLC 22 Taylor February 10, 2016 Georgia Power 20 years Approx. $45 (c) (a) Affiliate PPA approved by the FERC. (b) Affiliate PPA subject to FERC approval. (c) Includes the acquisition price of all outstanding membership interests of the respective development entity. |
Southern Power [Member] | |
Business Acquisition [Line Items] | |
ACQUISITIONS | ACQUISITIONS During 2015 and 2014, in accordance with the Company's overall growth strategy, the Company acquired or contracted to acquire through its wholly-owned subsidiaries, SRP or SRE, the projects set forth in the following table. Acquisition-related costs of approximately $4 million were expensed as incurred. The acquisitions do not include any contingent consideration unless specifically noted. 2015 Project Facility Seller; Acquisition Date Approx. Location Percentage Ownership Expected/Actual COD PPA PPA Approx. Purchase Price (MW) (in millions) WIND Kay Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 12, 2015 Westar Energy, Inc. and Grant River Dam Authority 20 years $ 481 (b) Grant Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % March 2016 Western Farmers, East Texas, and Northeast Texas Electric Cooperative 20 years $ 258 (c) SOLAR Lost Hills Blackwell First Solar 33 Kern County, CA 51 % (a) April 17, 2015 City of Roseville, California/Pacific Gas and Electric Company 29 years $ 73 (d) North Star First Solar 61 Fresno County, CA 51 % (a) June 20, 2015 Pacific Gas and Electric Company 20 years $ 208 (e) Tranquillity Recurrent Energy, LLC 205 Fresno County, CA 51 % (a) Fourth quarter 2016 Shell Energy North America (US), LP and then SCE 18 years $ 100 (f) Desert Stateline First Solar 299 San Bernardino County, CA 51 % (a) From December 2015 to third quarter 2016 (h) SCE 20 years $ 439 (g) Morelos Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % November 25, 2015 Pacific Gas and Electric Company 20 years $ 45 (i) Roserock Recurrent Energy, LLC 160 Pecos County, TX 51 % (a) Fourth quarter 2016 Austin Energy 20 years $ 45 (j) Garland and Garland A Recurrent Energy, LLC 205 Kern County, CA 51 % (a) Fourth quarter 2016 SCE 15 years 20 years $ 49 (k) Calipatria Solar Frontier Americas Holding, LLC 20 Imperial County, CA 90 % February 11, 2016 San Diego Gas & Electric Company 20 years $ 52 (l) (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. At each acquisition, the Company acquired a controlling interest in the entity owning the project facility and recorded approximately $227 million for the noncontrolling interests, in the aggregate, which is recorded as a non-cash transaction in contributions from noncontrolling interests and plant acquisitions. (b) Kay Wind - The total purchase price, including $35 million of contingent consideration, is approximately $481 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $481 million as CWIP, $8 million as a receivable related to transmission interconnection costs, and $8 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. (c) Grant Wind - On September 4, 2015, Southern Power entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at or near the expected COD. The purchase price includes approximately $24 million of contingent consideration and may be adjusted based on performance testing and production over the first 10 years of operation. The ultimate outcome of this matter cannot be determined at this time. (d) Lost Hills Blackwell - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $34 million . At the acquisition date, the members became contingently obligated to pay $3 million of construction payables through COD, making the aggregate purchase price approximately $107 million . The fair values of the assets acquired through the business combination were recorded as follows: $105 million as property, plant, and equipment, $3 million as a receivable related to transmission interconnection costs, and $4 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. (e) North Star - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $99 million . At the acquisition date, the members became contingently obligated to pay $233 million of construction payables through COD, making the aggregate purchase price approximately $307 million . The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $25 million as an intangible asset, $21 million as a receivable related to transmission interconnection costs, and $238 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The amortization expense for the year ended December 31, 2015 was $1 million . The estimated amortization for future periods is approximately $1.2 million per year for 2016 through 2020, and $18 million thereafter. (f) Tranquillity - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $173 million of assets and receiving an initial distribution of $100 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $186 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million . The ultimate outcome of this matter cannot be determined at this time. (g) Desert Stateline - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million . As of December 31, 2015, the fair values of the assets acquired through the business combination, which includes the Company's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion . The ultimate outcome of this matter cannot be determined at this time. (h) Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service. (i) Morelos - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $50 million . As of December 31, 2015, the fair values of the assets acquired through the business combination were recorded as follows: $49 million as property, plant, and equipment and $1 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. (j) Roserock - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $26 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $75 million as CWIP, $6 million as other receivables, and $10 million as payables and accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million . The ultimate outcome of this matter cannot be determined at this time. (k) Garland and Garland A - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $31 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $107 million as CWIP, $1 million as other deferred assets, and $28 million as payables and other accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million . The ultimate outcome of this matter cannot be determined at this time. (l) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $58 million . The aggregate amount of revenue recognized by to the Company related to the acquisitions, since the various acquisition dates, included in the consolidated statement of income for 2015 is $18 million . The aggregate amount of net income, excluding the impacts of ITCs, attributable to the Company related to the acquisitions, since the various acquisition dates, included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to their assets being constructed and placed in service; and therefore, supplemental proforma information as though the acquisitions occurred as of the beginning of 2015, and for the comparable 2014 year is not meaningful and has been omitted. 2014 Project Seller; Acquisition Date Approx. Nameplate Capacity Location Percentage Ownership COD PPA PPA Contract Period Approx. Purchase Price (MW) (in millions) SOLAR Adobe Sun Edison, LLC 20 Kern County, CA 90 % May 21, 2014 SCE 20 years $ 86 (b) Macho Springs First Solar Development, LLC 50 Luna County, NM 90 % May 23, 2014 EPE 20 years $ 117 (c) Imperial Valley First Solar, October 22, 2014 150 Imperial County, CA 51 % (a) November 26, 2014 San Diego Gas & Electric Company 25 years $ 505 (d) (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) Adobe - Total purchase price, including the minority owner TRE's 10% ownership interest, was $97 million . The fair values of the assets acquired were ultimately recorded as follows: $84 million to property, plant, and equipment, $15 million to prepayment related to transmission services, and $6 million to PPA intangible, resulting in a $5 million bargain purchase gain and a $3 million deferred tax liability. The bargain purchase gain is included in other income (expense), net. Acquisition-related costs were expensed as incurred and were not material. (c) Macho Springs - Total purchase price, including the minority owner TRE's 10% ownership interest, was $130 million . The fair values of the assets acquired were ultimately recorded as follows: $128 million to property, plant, and equipment, $1 million to prepaid property taxes, and $1 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material. (d) Imperial Valley - In connection with this acquisition, SG2 Holdings, LLC (SG2 Holdings) made an aggregate payment of approximately $128 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599 million upon completion of the facility (representing the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved in November 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by the Company for the acquisition of Imperial Valley was approximately $505 million in addition to the $223 million noncash contribution by the minority member. The fair values of the assets acquired were ultimately recorded as follows: $708 million to property, plant, and equipment and $20 million to prepayment related to transmission services. Acquisition-related costs were expensed as incurred and were not material. Construction Projects During 2015, in accordance with the Company's overall growth strategy, the Company constructed or commenced construction of the projects set forth in the table below, in addition to the Tranquillity, Desert Stateline, Roserock, Garland, and Garland A facilities. Total cost of construction incurred for these projects during 2015 was $1.8 billion , of which $1.1 billion remains in CWIP at December 31, 2015 . Solar Facility Seller Approx. Nameplate Capacity County Location in Georgia Expected/Actual COD PPA Counterparties PPA Contract Period Estimated Construction Cost (MW) (in millions) Sandhills N/A 146 Taylor Fourth quarter 2016 Cobb, Flint, and Sawnee EMCs 25 years $ 260 - 280 Decatur Parkway TradeWind Energy, Inc. 84 Decatur December 31, 2015 Georgia Power (a) 25 years Approx. $169 (c) Decatur County TradeWind Energy, Inc. 20 Decatur December 29, 2015 Georgia Power 20 years Approx. $46 (c) Butler CERSM, LLC and Community Energy, Inc. 103 Taylor Fourth quarter 2016 Georgia Power (b) 30 years $ 220 - 230 (c) Pawpaw Longview Solar, LLC 30 Taylor March 2016 Georgia Power (a) 30 years $ 70 - 80 (c) Butler Solar Farm Strata Solar Development, LLC 22 Taylor February 10, 2016 Georgia Power 20 years Approx. $45 (c) (a) Affiliate PPA approved by the FERC. (b) Affiliate PPA subject to FERC approval. (c) Includes the acquisition price of all outstanding membership interests of the respective development entity. |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters | 12 Months Ended |
Dec. 31, 2015 | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by 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. AGL Resources Merger Litigation AGL Resources and each member of the AGL Resources board of directors were named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia in September and October 2015. These actions were filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. On October 23, 2015, the court consolidated the four lawsuits into a single action. On January 4, 2016, the parties filed a proposed stipulated order of dismissal, asking the court to dismiss the consolidated amended complaint without prejudice, which the court approved on January 5, 2016. See Note 12 under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger. Environmental Matters Environmental Remediation The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs. Georgia Power's environmental remediation liability as of December 31, 2015 was $29 million . Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of other sites are anticipated. The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's financial statements. Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of December 31, 2015 . 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 substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income. The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements . Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract. In December 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. On March 19, 2015, Georgia Power recovered approximately $18 million , based on its ownership interests, and Alabama Power recovered approximately $26 million . In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. In November 2015, Alabama Power applied the retail-related proceeds to offset the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, Alabama Power credited the wholesale-related proceeds to each wholesale customer. In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. 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, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's net income is expected. On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant. FERC Matters The traditional 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 operating companies and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. The FERC directed the traditional 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 operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time. Retail 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% . 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, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. In 2013, the Alabama PSC approved a revision to Rate RSE, effective for calendar year 2014. This revision established the WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided 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. The Rate RSE increase for 2015 was 3.49% or $181 million annually, and was effective January 1, 2015. On November 30, 2015, Alabama Power made its annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2016. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016. Rate CNP Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015, 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, 2015 through March 31, 2016. No adjustment to Rate CNP PPA is expected in 2016. As of December 31, 2015 , Alabama Power had an under recovered certificated PPA balance of $99 million which is included in deferred under recovered regulatory clause revenues in the balance sheet. Rate CNP Environmental allowed for the recovery of Alabama Power's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. 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. Rate CNP Compliance increased 1.5% , or $75 million annually, effective January 1, 2015. As of December 31, 2015, Alabama Power had an under recovered compliance clause balance of $43 million , which is included in under recovered regulatory clause revenues in the balance sheet. Rate ECR Alabama Power has established energy cost recovery rates under Alabama Power's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on 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 December 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2015 the Rate ECR factor of 2.681 cents per KWH. On December 1, 2015, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7% , or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on Southern Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015. The rate will return to 2.681 cents per KWH in 2017 and 5.910 cents per KWH in 2018, absent a further order from the Alabama PSC. Alabama Power's over recovered fuel costs at December 31, 2015 totaled $238 million as compared to $47 million at December 31, 2014 . At December 31, 2015 , $238 million is included in other regulatory liabilities, current. The over recovered fuel costs at December 31, 2014 are included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. Rate NDR Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24 -month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million . Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. Environmental Accounting Order Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs, associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 ( 200 MWs). Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 ( 250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, Alabama Power retired Plant Barry Unit 3 ( 225 MWs) in August 2015 and it is no longer available for generation. Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 ( 300 MWs) and begin operating those units solely on natural gas by April 2016. In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements. Nuclear Waste Fund Accounting Order In 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014. In August 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for Alabama Power to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, Alabama Power transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense. Cost of Removal Accounting Order In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized in December 2014. Georgia Power Rate Plans In 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors. In January 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million ; (2) Environmental Compliance Cost Recovery (ECCR) tariff by approximately $25 million ; (3) Demand-Side Management (DSM) tariffs by approximately $1 million ; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million , for a total increase in base revenues of approximately $110 million . On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2015 as follows: (1) traditional base tariff rates by approximately $107 million ; (2) ECCR tariff by approximately $23 million ; (3) DSM tariffs by approximately $3 million ; and (4) MFF tariff by approximately $3 million , for a total increase in base revenues of approximately $136 million . On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase 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) DSM tariffs by approximately $3 million ; and (4) MFF tariff by approximately $13 million , for a total increase in base revenues of approximately $140 million . 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 2014, Georgia Power's retail ROE exceeded 12.00% , and Georgia Power will refund to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. Georgia Power is required to file a general base rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued. Integrated Resource Plan To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 ( 1,266 MWs), Plant Yates Units 1 through 5 ( 579 MWs), and Plant McManus Units 1 and 2 ( 122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 ( 155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 ( 316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015. In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. On January 29, 2016, Georgia Power filed its triennial IRP (2016 IRP). The filing included a request to decertify Plant Mitchell Units 3, 4A, and 4B ( 217 MWs) and Plant Kraft Unit 1 ( 17 MWs) upon approval of the 2016 IRP. The 2016 IRP also reflects that Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit ( 143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 for additional information. In the 2016 IRP, Georgia Power requested reclassification of the remaining net book value of Plant Mitchell Unit 3, as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. Georgia Power also requested that the Georgia PSC approve the deferral of the cost associated with materials and supplies remaining at the unit retirement dates to a regulatory asset, to be amortized over a period deemed appropriate by the Georgia PSC. The decertification and retirement of these units are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's orders in the 2016 IRP and next general base rate case. Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting to procure up to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand Georgia Power's existing renewable initiatives, including the Advanced Solar Initiative. A decision from the Georgia PSC on the 2016 IRP is expected in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this time. Fuel Cost Recovery Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in Georgia Power's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million . Georgia Power's fuel cost recovery includes costs associated with a natural gas hedging program, as approved by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48 -month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15, 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. Georgia Power's over recovered fuel balance totaled approximately $116 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014 , Georgia Power's under recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. Storm Damage Recovery Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, Georgia Power is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2015 and December 31, 2014 , the balance in the regulatory asset related to storm damage was $92 million and $98 million , respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62 million and $68 million included in other regulatory assets, deferred, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company's financial statements. Nuclear Construction In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million . Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7% . On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Desig |
Alabama Power [Member] | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by 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 costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract. In December 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. On March 19, 2015, the Company recovered approximately $26 million . In November 2015, the Company applied the retail-related proceeds to offset the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, the Company credited the wholesale-related proceeds to each wholesale customer. In March 2014, the Company filed an additional 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. 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, 2015 for any potential recoveries from this lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected. At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant. 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 operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. The FERC directed the traditional 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 operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter 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% . 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, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. In 2013, the Alabama PSC approved a revision to Rate RSE, effective for calendar year 2014. This revision established the WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided 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. The Rate RSE increase for 2015 was 3.49% or $181 million annually, and was effective January 1, 2015. On November 30, 2015, the Company made its annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2016. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016. Rate CNP The Company's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015, 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, 2015 through March 31, 2016. No adjustment to Rate CNP PPA is expected in 2016. As of December 31, 2015 , the Company had an under recovered certificated PPA balance of $99 million which is included in deferred under recovered regulatory clause revenues in the balance sheet. Rate CNP Environmental allowed for the recovery of the Company's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. The Company was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. 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. Rate CNP Compliance increased 1.5% , or $75 million annually, effective January 1, 2015. As of December 31, 2015, the Company had an under recovered compliance clause balance of $43 million , which is included in under recovered regulatory clause revenues in the balance sheet. Rate ECR The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that the Company leave in effect for 2015 the Rate ECR factor of 2.681 cents per KWH. On December 1, 2015, the Alabama PSC approved a decrease in the Company’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7% , or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on the Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015. The rate will return to 2.681 cents per KWH in 2017 and 5.910 cents per KWH in 2018, absent a further order from the Alabama PSC. The Company's over recovered fuel costs at December 31, 2015 totaled $238 million as compared to $47 million at December 31, 2014. At December 31, 2015, $238 million is included in other regulatory liabilities, current. The over recovered fuel costs at December 31, 2014 are included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. Rate NDR Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24 -month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million . The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. Environmental Accounting Order Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs, associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. In April 2015, as part of its environmental compliance strategy, the Company retired Plant Gorgas Units 6 and 7 ( 200 MWs). Additionally, in April 2015, the Company ceased using coal at Plant Barry Units 1 and 2 ( 250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, the Company retired Plant Barry Unit 3 ( 225 MWs) in August 2015 and it is no longer available for generation. The Company expects to cease using coal at Plant Greene County Units 1 and 2 ( 300 MWs) and begin operating those units solely on natural gas by April 2016. In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on the Company's financial statements. Nuclear Waste Fund Accounting Order In 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014. In August 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, the Company was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for the Company to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, the Company transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense. Cost of Removal Accounting Order In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized in December 2014. |
Georgia Power [Member] | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by 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 may also incur substantial costs to clean up affected sites. See Note 1 under "Environmental Remediation Recovery" for additional information. The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, the Company entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between the Company and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of other sites are anticipated. The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the Company's regulatory treatment for environmental remediation expenses described in Note 1 under "Environmental Remediation Recovery," these matters are not expected to have a material impact on the Company's financial statements. Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with the Company that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Hatch and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract. In December 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. On March 19, 2015, the Company recovered approximately $18 million , based on its ownership interests. In March 2015, the Company credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. In March 2014, the Company filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. 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, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on the Company's net income is expected. 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 operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. The FERC directed the traditional 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 operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time. Retail Regulatory Matters Rate Plans In 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among the Company, the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors. In January 2014, in accordance with the 2013 ARP, the Company increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million ; (2) ECCR tariff by approximately $25 million ; (3) Demand-Side Management (DSM) tariffs by approximately $1 million ; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million , for a total increase in base revenues of approximately $110 million . On February 19, 2015 , in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2015 as follows: (1) traditional base tariff rates by approximately $107 million ; (2) ECCR tariff by approximatel y $23 million ; (3) DSM tariffs by approximately $3 million ; and (4) MFF tariff by approximately $3 million , for a total increase in base revenues of approximately $136 million . On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase 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) DSM tariffs by approximately $3 million ; and (4) MFF tariff by approximately $13 million , for a total increase in base revenues of approximately $140 million . 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 2014, the Company's retail ROE exceeded 12.00% , and the Company will refund to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, the Company's retail ROE was within the allowed retail ROE range. The Company is required to file a general base rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued. Integrated Resource Plan To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 ( 1,266 MWs) , Plant Yates Units 1 through 5 ( 579 MWs) , and Plant McManus Units 1 and 2 ( 122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 ( 155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 ( 316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015. In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. On January 29, 2016, the Company filed its triennial IRP (2016 IRP). The filing included a request to decertify Plant Mitchell Units 3, 4A, and 4B ( 217 MWs) and Plant Kraft Unit 1 ( 17 MWs) upon approval of the 2016 IRP. The 2016 IRP also reflects that the Company exercised its contractual option to sell its 33% ownership interest in the Intercession City unit ( 143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 for additional information. In the 2016 IRP, the Company requested reclassification of the remaining net book value of Plant Mitchell Unit 3, as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. The Company also requested that the Georgia PSC approve the deferral of the cost associated with materials and supplies remaining at the unit retirement dates to a regulatory asset, to be amortized over a period deemed appropriate by the Georgia PSC. The decertification and retirement of these units are not expected to have a material impact on the Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's orders in the 2016 IRP and next general base rate case. Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting to procure up to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand the Company’s existing renewable initiatives, including the Advanced Solar Initiative. A decision from the Georgia PSC on the 2016 IRP is expected in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this time. Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in the Company's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, the Company continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million . The Company's fuel cost recovery includes costs associated with a natural gas hedging program, as approved by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48 -month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15, 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. The Company's over recovered fuel balance totaled approximately $116 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014 , the Company's under recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow. Nuclear Construction In 2008, the Company, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to the Company (based on the Company's ownership interest) of approximately $114 million . Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. The Company's proportionate share is 45.7% . On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges may arise as construction proceeds. In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. 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 by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an initial NCCR tariff of approximately $223 million effective January 1, 2011, as well as increases to the NCCR tariff of approximately $35 million , $50 million , $60 million , $27 million , and $19 million effective January 1, 2012, 2013, 2014, 2015, and 2016, respectively. The Company is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by the Company increase by 5% above the certified cost or the projected in-service dates are significantly extended, the Company is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, the Company requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and the Company. On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18 -month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion . Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by the Company in excess of the certified amount will be included in rate base, provided the Company shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC. In 2012, the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on the Company's ownership interest) of approximately $714 million (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, the Company, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that the Company, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million , of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, the Company paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in the Company's previously disclosed in-service cost estimate. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice. On January 21, 2016, the Company submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered the Company to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and the Company's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following the Company's filing under the order, the Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with the Company and any intervenors. The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing the Company to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority. The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion . On February 26, 2016, the Company filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. The Company is requesting approval of $160 million of construction capital costs incurred during that period. The Company anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion . The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6 billion as of December 31, 2015. Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both. As construction continues, the risk remains that challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021. Future claims by the Contractor or the Company (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units. The ultimate outcome of these matters cannot be determined at this time. |
Gulf Power [Member] | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by 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 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. At December 31, 2015 , the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $46 million , of which approximately $4 million is included in under recovered regulatory clause revenues and other current liabilities and approximately $42 million is included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company's environmental cost recovery clause; therefore, these liabilities have no impact on net income. The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements. 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 operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. The FERC directed the traditional 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 operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter 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 Case In 2013, the Florida PSC voted to approve the 2013 Rate Case Settlement Agreement among the Company and all of the intervenors to the Company's retail base rate case. Under the terms of the 2013 Rate Case Settlement Agreement, the Company (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint ( 10.25% ) and range ( 9.25% – 11.25% ); and (3) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first. The 2013 Rate Case Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized retail ROE midpoint and range by 25 basis points in the event the 30 -year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six -month period. The 2013 Rate Case Settlement Agreement also provides that the Company may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company's next base rate case or next depreciation and dismantlement study proceeding, whichever comes first. For 2015 and 2014, the Company recognized reductions in depreciation expense of $20.1 million and $8.4 million , respectively. Pursuant to the 2013 Rate Case Settlement Agreement, the Company may not request an increase in its retail base rates to be effective until after June 2017, unless the Company's actual retail ROE falls below the authorized ROE range. Cost Recovery Clauses On November 2, 2015, the Florida PSC approved the Company's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2016. The net effect of the approved changes is an expected $49 million decrease in annual revenue for 2016. The decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor for fuel and purchased power will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. The recovery provisions for environmental compliance and energy conservation include related expenses and a return on net average investment. Retail Fuel Cost Recovery The Company has established fuel cost recovery rates as approved by the Florida PSC. If, at any time during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested. At December 31, 2015 , the over recovered fuel balance was approximately $18 million , which is included in other regulatory liabilities, current in the balance sheets. At December 31, 2014 , the under recovered fuel balance was approximately $40 million , which is included in under recovered regulatory clause revenues in the balance sheets. Purchased Power Capacity Recovery The Company has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected year-end purchased power capacity cost over or under recovery balance exceeds 10% of the projected purchased power capacity revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the purchased power capacity cost recovery factor is being requested. At December 31, 2015 and 2014, the under recovered purchased power capacity balance was immaterial. Environmental Cost Recovery The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emissions allowance expense, depreciation, and a return on net average investment. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. In 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company's plan for complying with certain federal and state regulations addressing air quality. The Company's environmental compliance plan as filed in 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The Florida PSC's approval of the stipulation also required the Company to file annual updates to the plan and outlined a process for approval of additional elements in the plan when they became committed projects. In the 2010 update filing, the Company identified several elements of the updated plan that the Company had decided to implement. Following the process outlined in the original approved stipulation, these additional projects were approved by the Florida PSC later in 2010. The Florida PSC acknowledged that the costs of the approved projects associated with the Company's Clean Air Interstate Rule and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2015 , the under recovered environmental balance was immaterial. At December 31, 2014 , the under recovered environmental balance was approximately $10 million , which is included in under recovered regulatory clause revenues in the balance sheets. In 2012, the Mississippi PSC approved Mississippi Power's request for a certificate of public convenience and necessity to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by Mississippi Power and the Company, with 50% ownership each. The total cost of the project was approximately $653 million , with the Company's portion being approximately $316 million , excluding AFUDC. The Company's portion of the cost is being recovered through the environmental cost recovery clause. Energy Conservation Cost Recovery Every five years , the Florida PSC establishes new numeric conservation goals covering a 10 -year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the energy conservation cost recovery (ECCR) clause. At December 31, 2015 , the over recovered ECCR balance was approximately $4 million , which is included in other regulatory liabilities, current in the balance sheet. At December 31, 2014 , the under recovered ECCR balance was approximately $3 million , which is included in under recovered regulatory clause revenues in the balance sheet. |
Mississippi Power [Member] | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by 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 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 regulatory mechanisms. FERC Matters Municipal and Rural Associations Tariff In 2012, the Company entered into a settlement agreement with its wholesale customers with respect to the Company's request for revised rates under the wholesale cost-based electric tariff. The settlement agreement provided that base rates under the cost-based electric tariff increase by approximately $23 million over a 12 -month period with revised rates effective April 1, 2012. A significant portion of the difference between the requested base rate increase and the agreed upon rate increase was due to a change in the recovery methodology for the return on the Kemper IGCC CWIP. Under the settlement agreement, a portion of CWIP will continue to accrue AFUDC. The tariff customers specifically agreed to the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC with respect to (i) the accounting for Kemper IGCC-related costs that cannot be capitalized, (ii) the accounting for the lease termination and purchase of Plant Daniel Units 3 and 4, and (iii) the establishment of a regulatory asset for certain potential plant retirement costs. Also in 2012, the FERC approved a motion to place interim rates into effect beginning in May 2012. Later in 2012, the Company, with its wholesale customers, filed a final settlement agreement with the FERC. In 2013, the Company received an order from the FERC accepting the settlement agreement. In 2013, the Company reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the MRA cost-based electric tariff, which was accepted by the FERC in 2013. The 2013 settlement agreement provided that base rates under the MRA cost-based electric tariff will increase by approximately $24 million annually, effective April 1, 2013. In March 2014, the Company reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the MRA cost-based electric tariff. The settlement agreement, accepted by the FERC in May 2014, provided that base rates under the MRA cost-based electric tariff increased approximately $10 million annually, effective May 1, 2014. Included in this settlement agreement, an adjustment to the Company's wholesale revenue requirement in a subsequent rate proceeding was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, the Company recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date, which was fully amortized as of December 31, 2015. On May 13, 2015, the FERC accepted a further settlement agreement between the Company and its wholesale customers to forgo a MRA cost-based electric tariff increase by, among other things, increasing the accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015. The additional resulting AFUDC is estimated to be approximately $14 million annually, of which $11 million relates to the Kemper IGCC. Fuel Cost Recovery The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2016, the wholesale MRA fuel rate decreased $47 million annually. Effective February 1, 2016, the wholesale MB fuel rate decreased $2 million annually. At December 31, 2015 , the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $24 million compared to an immaterial balance at December 31, 2014 . 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 operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. The FERC directed the traditional 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 operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter 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. The ultimate outcome of this matter 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 required to be filed within six months of the order and will be in effect for two to three years . An annual report addressing the performance of all energy efficiency programs is required. In June 2014, the Mississippi PSC approved the Company's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. In November 2014, the Mississippi PSC approved the Company's revised compliance filing, which included an increase of $7 million in retail revenues for the period December 2014 through December 2015. Performance Evaluation Plan The Company’s retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on projected revenue requirement, and the PEP lookback filing, which is filed after the year and allows for review of the actual revenue requirement compared to the projected filing. PEP was designed with the objective to reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability. In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. 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 certain costs included in the 2010 PEP lookback filing, which are currently 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 March 2014 and 2015, the Company submitted its annual PEP lookback filings for 2013 and 2014, respectively, which each indicated no surcharge or refund. The Mississippi PSC suspended each of the filings to allow more time for review. In June 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi. The ultimate outcome of these matters cannot be determined at this time. Environmental Compliance Overview Plan In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. The Company's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of December 31, 2015 , total project expenditures were $637 million , of which the Company's portion was $325 million , excluding AFUDC of $36 million . In 2013, the Mississippi PSC approved the Company’s 2013 ECO Plan filing which proposed no change in rates. In August 2014, the Company entered into a settlement agreement with the Sierra Club that, among other things, required the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which also occurred in August 2014. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 ( 80 MWs) no later than December 2018. The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 ( 750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred on April 16, 2015), and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 ( 200 MWs) and begin operating those units solely on natural gas no later than April 2016. In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. This request was made to minimize the potential rate impact to customers arising from pending and final environmental regulations which may require the premature retirement of some generating units. As of December 31, 2015, $5 million of Plant Greene County costs and $36 million of costs related to Plant Watson have been reclassified as regulatory assets. These costs are expected to be recovered through the ECO plan and other existing cost recovery mechanisms. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Watson and Greene County in 2016. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on the Company's financial statements. On December 3, 2015, the Mississippi PSC approved the Company's revised ECO filing for 2015, which indicated no change in revenue. Fuel Cost Recovery The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. The Mississippi PSC approved the 2016 retail fuel cost recovery factor, effective January 21, 2016, which will result in an annual revenue decrease of approximately $120 million . At December 31, 2015 , the amount of over-recovered retail fuel costs included in the balance sheets was $71 million compared to a $3 million under-recovered balance at December 31, 2014 . 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 September 1, 2015, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing effective September 18, 2015, which included an annual rate decrease of 0.35% , or $2 million in annual retail revenues, primarily due to average millage rates. System Restoration Rider On October 6, 2015, the Mississippi PSC approved the Company's 2015 SRR rate filing, which proposed that the SRR rate remain level at zero and the Company continue to accrue $3 million annually to the property damage reserve. On February 1, 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. The ultimate outcome of this matter cannot be determined at this time. See Note 1 under "Provision for Property Damage" for additional information. Integrated Coal Gasification Combined Cycle Kemper IGCC Overview Construction of the Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, the Company constructed and plans to operate approximately 61 miles of CO 2 pipeline infrastructure for the planned transport of captured CO 2 for use in enhanced oil recovery. Kemper IGCC Schedule and Cost Estimate In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC . The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion , net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO 2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016. Recovery of the costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO 2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of December 31, 2015 , are as follows: Cost Category 2010 Project Estimate (f) Current Cost Estimate (a) Actual Costs (in billions) Plant Subject to Cost Cap (b)(g) $ 2.40 $ 5.29 $ 4.83 Lignite Mine and Equipment 0.21 0.23 0.23 CO 2 Pipeline Facilities 0.14 0.11 0.11 AFUDC (c) 0.17 0.69 0.59 Combined Cycle and Related Assets Placed in Service – Incremental (d)(g) — 0.01 0.01 General Exceptions 0.05 0.10 0.09 Deferred Costs (e)(g) — 0.20 0.17 Total Kemper IGCC $ 2.97 $ 6.63 $ 6.03 (a) Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016. (b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information. (c) The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information. (d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. (e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein. (f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO 2 pipeline facilities which was approved in 2011 by the Mississippi PSC. (g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015. Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2015 , $3.47 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.41 billion ), $2 million in other property and investments, $69 million in fossil fuel stock, $45 million in materials and supplies, $21 million in other regulatory assets, current, $195 million in other regulatory assets, deferred, and $11 million in other deferred charges and assets in the balance sheet. The Company does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. The Company recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $365 million ( $226 million after tax), $868 million ( $536 million after tax), and $1.1 billion ( $681 million after tax) in 2015, 2014, and 2013, respectively. The increases to the cost estimate in 2015 primarily reflect costs for the extension of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein. The Company's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of operations and these changes could be material. Rate Recovery of Kemper IGCC Costs See "FERC Matters" herein for additional information regarding the Company's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from the Company's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Income Tax Matters" herein for additional tax information related to the Kemper IGCC. The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity. 2012 MPSC CPCN Order The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company's petition for the CPCN. The Company expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or the Company incurs additional costs to satisfy such parameters, there could be a material adverse impact on the Company's financial statements. 2013 MPSC Rate Order In January 2013, the Company entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC. The Company will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million . The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation discussed below. 2015 Rate Case As a result of the 2015 Court decision, on July 10, 2015, the Company filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover the Company's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions. On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between the Company and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, the In-Service Asset Rate Order provides 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 during the test period. The In-Service Asset Rate Order also includes a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excludes the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA . See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information. With implementation of the new rate on December 17, 2015, the interim rates were terminated and the Company recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016. Pursuant to the In-Service Asset Rate Order, the Company is required to file a subsequent rate request within 18 months . As part of the filing, the Company expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation. On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the 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 ultimate outcome of this matter cannot be determined at this time. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. The Company expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion . Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact the Company's ability to utilize alternate financing through securitization or the February 2013 legislation. The Company expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015 of $6.63 billion , the Company anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost |
Southern Power [Member] | |
Loss Contingencies [Line Items] | |
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by 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. 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 operating companies and the Company filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. The FERC directed the traditional 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 operating companies and the Company filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time. |
Joint Ownership Agreements
Joint Ownership Agreements | 12 Months Ended |
Dec. 31, 2015 | |
Joint Ownership Agreements [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, the City of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Duke Energy Florida, Inc. for a combustion turbine unit at Intercession City, Florida. Subsequent to December 31, 2015, Georgia Power exercised its contractual option to sell its ownership interest to Duke Energy Florida, Inc. contingent on regulatory approvals. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. At December 31, 2015 , Alabama Power's, Georgia Power's, and Southern Power's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: Facility (Type) Percent Ownership Plant in Service Accumulated Depreciation CWIP (in millions) Plant Vogtle (nuclear) Units 1 and 2 45.7 % $ 3,503 $ 2,084 $ 63 Plant Hatch (nuclear) 50.1 1,230 568 90 Plant Miller (coal) Units 1 and 2 91.8 1,518 587 63 Plant Scherer (coal) Units 1 and 2 8.4 260 86 1 Plant Wansley (coal) 53.5 915 290 13 Rocky Mountain (pumped storage) 25.4 181 125 — Intercession City (combustion turbine) 33.3 13 4 — Plant Stanton (combined cycle) Unit A 65.0 157 53 — Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" for additional information. Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain and Intercession City, 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. |
Alabama Power [Member] | |
Joint Ownership Agreements [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a power contract. The Company and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and ROE. The Company's share of purchased power totaled $76 million in 2015 , $84 million in 2014 , and $88 million in 2013 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, 2015 , the capitalization of SEGCO consisted of $118 million of equity and $125 million of long-term debt on which the annual interest requirement is $3 million . In addition, SEGCO had short-term debt outstanding of $52 million . SEGCO paid an immaterial amount of dividends in 2015 compared to $3 million in 2014 and $7 million in 2013 , of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net income. SEGCO added natural gas as a fuel source for 1,000 MWs of its generating capacity in 2015. In April 2016, natural gas will become the primary fuel source. The Company, which owns and operates a generating unit adjacent to the SEGCO generating units, has entered into a joint ownership agreement with SEGCO for the ownership of the gas pipeline. The Company 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 the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2015 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) $ 159 $ 97 $ 20 Plant Miller Units 1 and 2 1,320 91.84 % (2) 1,518 587 63 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth Energy Cooperative, Inc. The Company has contracted to operate and maintain the jointly-owned facilities as agent for their co-owners. The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the Company is responsible for providing its own financing. |
Georgia Power [Member] | |
Joint Ownership Agreements [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Alabama Power under a power contract. The Company and Alabama Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and a ROE. The Company's share of purchased power totaled $78 million in 2015 , $84 million in 2014 , and $91 million in 2013 and is included in purchased power, affiliates in the statements of income. The Company accounts for SEGCO using the equity method. The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Duke Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Duke Energy Florida, Inc. Subsequent to December 31, 2015, the Company exercised its contractual option to sell its ownership interest to Duke Energy Florida, Inc. contingent on regulatory approvals. The ultimate outcome of this matter cannot be determined at this time; however, no material impact on the Company's financial statements is expected. At December 31, 2015 , 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 % $ 3,503 $ 2,084 $ 63 Plant Hatch (nuclear) 50.1 1,230 568 90 Plant Wansley (coal) 53.5 915 290 13 Plant Scherer (coal) Units 1 and 2 8.4 260 86 1 Unit 3 75.0 1,223 433 1 Rocky Mountain (pumped storage) 25.4 181 125 — Intercession City (combustion-turbine) 33.3 13 4 — The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing. The Company also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information. |
Gulf Power [Member] | |
Joint Ownership Agreements [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units. The Company and Georgia Power jointly own the 818 MWs capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit. At December 31, 2015 , 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 $ 395 $ 669 Accumulated depreciation 136 184 Construction work in progress 2 9 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 [Member] | |
Joint Ownership Agreements [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company. In August 2014, a decision was made to cease coal operations at Greene County Steam Plant and convert to natural gas no later than April 16, 2016. As a result, active construction projects related to these assets were cancelled in September 2014. Associated amounts in CWIP of $6 million , reflecting the Company's share of the costs, were subsequently transferred to regulatory assets. See Note 3 under "Retail Regulatory Matters-Environmental Compliance Overview Plan" for additional information. At December 31, 2015 , 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 % $ 152 $ 56 $ 13 Daniel Units 1 and 2 50 % $ 686 $ 160 $ 10 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 [Member] | |
Joint Ownership Agreements [Line Items] | |
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS The Company is a 65% owner of Plant Stanton A, a combined-cycle project unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission ( 28% ), Florida Municipal Power Agency ( 3.5% ), and Kissimmee Utility Authority ( 3.5% ). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2015 , $157 million was recorded in plant in service with associated accumulated depreciation of $53 million . These amounts represent the Company's share of the total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the statements of income. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
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. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current $ (177 ) $ 175 $ 363 Deferred 1,266 695 386 1,089 870 749 State — Current (33 ) 93 (10 ) Deferred 138 14 110 105 107 100 Total $ 1,194 $ 977 $ 849 Net cash payments (refunds) for income taxes in 2015 , 2014 , and 2013 were $(9) million , $272 million , and $139 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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation $ 12,767 $ 11,125 Property basis differences 1,543 1,332 Leveraged lease basis differences 308 299 Employee benefit obligations 579 613 Premium on reacquired debt 95 103 Regulatory assets associated with employee benefit obligations 1,378 1,390 Regulatory assets associated with AROs 1,422 871 Other 586 523 Total 18,678 16,256 Deferred tax assets — Federal effect of state deferred taxes 479 430 Employee benefit obligations 1,720 1,675 Over recovered fuel clause 104 — Other property basis differences 695 453 Deferred costs 83 86 ITC carryforward 742 480 Unbilled revenue 111 67 Other comprehensive losses 85 89 AROs 1,422 871 Estimated Loss on Kemper IGCC 451 631 Deferred state tax assets 220 117 Other 246 342 Total 6,358 5,241 Valuation allowance (2 ) (49 ) Total deferred tax assets 6,356 5,192 Accumulated deferred income taxes $ 12,322 $ 11,064 On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million , with $488 million to non-current accumulated deferred income taxes and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014. At December 31, 2015 , Southern Company had subsidiaries with NOL carryforwards for the states of Georgia, Mississippi, New Mexico, and Florida totaling approximately $697 million , $3.0 billion , $133 million , and $115 million , respectively, which could result in net state income tax benefits of $27 million , $97 million , $5 million , and $4 million , respectively, if utilized. These NOLs expire between 2017 and 2035, but are expected to be fully utilized by 2029. During the second quarter 2015, an agreement was reached with the Georgia Department of Revenue that will allow Southern Company to utilize a portion of the NOL carryforward over a four -year period beginning in 2017. Consequently, Southern Company reversed the related valuation allowance and recognized approximately $24 million in net tax benefits. During 2015, approximately $87 million in New Mexico NOLs expired resulting in a $3.5 million net state income tax increase and a corresponding decrease in the valuation allowance, with no tax impact. At December 31, 2015 , the tax-related regulatory assets to be recovered from customers were $1.6 billion . These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. At December 31, 2015 , the tax-related regulatory liabilities to be credited to customers were $187 million . These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. In accordance with regulatory requirements, deferred federal ITCs for the traditional operating companies 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 $21 million in 2015 , $22 million in 2014 , and $16 million in 2013 . 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 $19 million in 2015 , $11 million in 2014 , and $6 million in 2013 . Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million , $74 million , and $158 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, which had a material impact on cash flows. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $54 million in 2015 , $48 million in 2014 , and $31 million in 2013 . At December 31, 2015 , Southern Company had federal ITC carryforwards which are expected to result in $554 million of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2020. Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling $188 million , which will expire between 2020 and 2026, but are expected to be fully utilized by 2022. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 1.9 2.3 2.5 Employee stock plans dividend deduction (1.2 ) (1.4 ) (1.6 ) Non-deductible book depreciation 1.2 1.4 1.5 AFUDC-Equity (2.2 ) (2.9 ) (2.6 ) ITC basis difference (1.5 ) (1.6 ) (1.2 ) Other (0.3 ) (0.3 ) (0.5 ) Effective income tax rate 32.9 % 32.5 % 33.1 % Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ 170 $ 7 $ 70 Tax positions increase from current periods 43 64 3 Tax positions increase from prior periods 240 102 — Tax positions decrease from prior periods (20 ) (3 ) (66 ) Balance at end of year $ 433 $ 170 $ 7 The tax positions increase from current periods and prior periods for 2015 and 2014 relate primarily to deductions for R&E expenditures associated with the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction" herein for more information. The tax positions decrease from prior periods for 2015 and 2014 relates to federal and state income tax credits. The tax positions decrease from prior periods for 2013 relate primarily to the Company's compliance with final U.S. Treasury regulations that resulted in a tax accounting method change for repairs. The impact on Southern Company's effective tax rate, if recognized, is as follows: 2015 2014 2013 (in millions) Tax positions impacting the effective tax rate $ 10 $ 10 $ 7 Tax positions not impacting the effective tax rate 423 160 — Balance of unrecognized tax benefits $ 433 $ 170 $ 7 The tax positions impacting the effective tax rate for 2015 , 2014 , and 2013 primarily relate to federal and state income tax credits. The tax positions not impacting the effective tax rate for 2015 and 2014 relate to deductions for R&E expenditures associated with the Kemper IGCC. 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 unrecognized tax benefits 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 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011. Section 174 Research and Experimental Deduction Southern Company reduced tax payments for 2015 and included in its 2013 and 2014 consolidated federal income tax returns deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. The Kemper IGCC is based on first-of-a-kind technology, and Southern Company believes that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Southern Company had related unrecognized tax benefits associated with these R&E deductions of approximately $423 million and associated interest of $9 million as of December 31, 2015. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time. |
Alabama Power [Member] | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and 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. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current $ 110 $ 198 $ 243 Deferred 320 225 160 430 423 403 State — Current 8 44 36 Deferred 68 45 39 76 89 75 Total $ 506 $ 512 $ 478 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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation $ 3,917 $ 3,429 Property basis differences 456 457 Premium on reacquired debt 28 30 Employee benefit obligations 200 215 Regulatory assets associated with employee benefit obligations 375 366 Asset retirement obligations 289 59 Regulatory assets associated with asset retirement obligations 312 285 Other 175 157 Total 5,752 4,998 Deferred tax assets — Federal effect of state deferred taxes 242 219 Unbilled fuel revenue 39 42 Storm reserve 23 27 Employee benefit obligations 407 400 Other comprehensive losses 20 19 Asset retirement obligations 600 344 Other 180 90 Total 1,511 1,141 Accumulated deferred income taxes, net $ 4,241 $ 3,857 On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-current accumulated deferred income taxes in the Company’s December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014. At December 31, 2015 , the tax-related regulatory assets to be recovered from customers were $523 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, 2015 , the tax-related regulatory liabilities to be credited to customers were $70 million . These liabilities are primarily attributable to unamortized ITCs. In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $8 million in 2015, 2014 and 2013. At December 31, 2015 , 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: 2015 2014 2013 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.8 4.4 4.0 Non-deductible book depreciation 1.2 1.1 1.0 Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.1) AFUDC equity (1.6) (1.3) (0.9) Other 0.1 (0.1) (0.1) Effective income tax rate 38.4% 39.0% 38.9% Unrecognized Tax Benefits The Company has no material unrecognized tax benefits for 2015 or 2014. 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 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. 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 [Member] | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and 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. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal – Current $ 515 $ 295 $ 277 Deferred 176 366 374 691 661 651 State – Current 81 82 (30 ) Deferred (3 ) (14 ) 102 78 68 72 Total $ 769 $ 729 $ 723 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: 2015 2014 (in millions) Deferred tax liabilities – Accelerated depreciation $ 4,909 $ 4,732 Property basis differences 943 811 Employee benefit obligations 310 329 Under-recovered fuel costs — 81 Premium on reacquired debt 61 66 Regulatory assets associated with employee benefit obligations 528 534 Asset retirement obligations 706 497 Other 187 160 Total 7,644 7,210 Deferred tax assets – Federal effect of state deferred taxes 150 148 Employee benefit obligations 642 642 Other property basis differences 88 86 Other deferred costs 83 86 Cost of removal obligations 6 11 State investment tax credit carryforward 188 152 Federal tax credit carryforward 3 5 Over-recovered fuel costs 45 — Unbilled fuel revenue 47 46 Asset retirement obligations 706 497 Other 59 63 Total 2,017 1,736 Accumulated deferred income taxes $ 5,627 $ 5,474 On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from prepaid income taxes of $34 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014. At December 31, 2015 , tax-related regulatory assets to be recovered from customers were $683 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, 2015 , tax-related regulatory liabilities to be credited to customers were $105 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 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 2015 , $10 million in 2014 , and $5 million in 2013 . State investment tax and other tax credits are recognized in the period in which the credits are claimed on the state income tax return and totaled $33 million in 2015, $34 million in 2014, and $27 million in 2013. At December 31, 2015 , the Company had $3 million in federal tax credit carryforwards that will expire by 2035 and $188 million in state ITC carryforwards that will expire between 2020 and 2026. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.5 2.2 2.5 Non-deductible book depreciation 1.2 1.3 1.3 AFUDC equity (0.7) (0.8) (0.6) Other (0.4) (0.7) (0.4) Effective income tax rate 37.6% 37.0% 37.8% The changes in the Company's effective tax rate are primarily the result of benefits related to emission allowances and state apportionment recorded in 2014. Unrecognized Tax Benefits Changes in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ — $ — $ 23 Tax positions increase from prior periods 3 — — Tax positions decrease from prior periods — — (23 ) Balance at end of year $ 3 $ — $ — The tax positions increase from prior periods for 2015 primarily relates to a graduated tax rate adjustment on the 2014 federal income tax return and will impact the Company's effective tax rate, if recognized. The tax positions decrease from prior periods for 2013 primarily relates to the Company's compliance with final U.S. Treasury regulations for a tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. 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 [Member] | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and 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. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal - Current $ (3 ) $ 23 $ 5 Deferred 80 52 63 77 75 68 State - Current 5 — (2 ) Deferred 10 13 14 15 13 12 Total $ 92 $ 88 $ 80 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: 2015 2014 (in millions) Deferred tax liabilities- Accelerated depreciation $ 812 $ 777 Property basis differences 133 52 Fuel recovery clause — 16 Pension and other employee benefits 39 34 Regulatory assets associated with employee benefit obligations 59 60 Regulatory assets associated with asset retirement obligations 40 7 Other 26 22 Total 1,109 968 Deferred tax assets- Federal effect of state deferred taxes 33 31 Postretirement benefits 26 18 Pension and other employee benefits 65 66 Property reserve 15 13 Asset retirement obligations 40 7 Alternative minimum tax carryforward 18 18 Other 19 18 Total 216 171 Accumulated deferred income taxes $ 893 $ 797 On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from prepaid expenses of $3 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014. At December 31, 2015 , tax-related regulatory assets to be recovered from customers were $61 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, 2015 , the tax-related regulatory liabilities to be credited to customers were $3 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 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 approximately $1 million annually for 2015 , 2014 , and 2013 . At December 31, 2015 , 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: 2015 2014 2013 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.9 3.5 3.5 Non-deductible book depreciation 0.5 0.4 0.5 Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.2) AFUDC equity (1.8) (1.8) (1.1) Other, net (0.6) 0.1 (0.1) Effective income tax rate 36.9% 37.1% 37.6% Unrecognized Tax Benefits The Company has no material unrecognized tax benefits for 2015 or 2014. 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 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. 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 [Member] | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and 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. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current $ (768 ) $ (431 ) $ 23 Deferred 704 183 (343 ) (64 ) (248 ) (320 ) State — Current (81 ) 1 5 Deferred 73 (38 ) (53 ) (8 ) (37 ) (48 ) Total $ (72 ) $ (285 ) $ (368 ) 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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation $ 1,618 $ 1,068 ECM under recovered 13 — Regulatory assets associated with AROs 71 19 Pensions and other benefits 30 35 Regulatory assets associated with employee benefit obligations 66 68 Regulatory assets associated with the Kemper IGCC 86 62 Rate differential 115 89 Federal effect of state deferred taxes — 1 Fuel clause under recovered — 3 Other 163 52 Total 2,162 1,397 Deferred tax assets — Fuel clause over recovered 51 — Estimated loss on Kemper IGCC 451 631 Pension and other benefits 92 92 Property insurance 25 24 Premium on long-term debt 18 21 Unbilled fuel 16 15 AROs 71 19 Interest rate hedges 4 5 Kemper rate factor - regulatory liability retail — 108 Property basis difference 451 263 ECM over recovered — 1 Deferred state tax assets 152 57 Deferred federal tax assets 48 — Federal effect of state deferred taxes 8 — Other 13 15 Total 1,400 1,251 Total deferred tax liabilities, net 762 146 Deferred state tax asset — 34 Accumulated deferred income taxes $ 762 $ 180 On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from prepaid income taxes of $121 million with $105 million to non-current accumulated deferred income taxes and $16 million to other deferred charges in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014. At December 31, 2015 , the tax-related regulatory assets were $291 million . These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest. At December 31, 2015 , the tax-related regulatory liabilities were $8 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 IGCC related deferred ITCs amortized in this manner amounted to $1 million in each of 2015, 2014, and 2013. At December 31, 2015, the Company had state of Mississippi NOL carryforwards totaling approximately $3 billion , resulting in deferred tax assets of approximately $97 million . The NOLs will expire between 2033 and 2035, but are expected to be fully utilized by 2028. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate (35.0 )% (35.0 )% (35.0 )% State income tax, net of federal deduction (6.3 ) (4.0 ) (3.7 ) Non-deductible book depreciation 1.3 0.1 0.1 AFUDC-equity (49.6 ) (7.8 ) (5.0 ) Other (2.9 ) 0.1 (0.1 ) Effective income tax rate (benefit rate) (92.5 )% (46.6 )% (43.7 )% The increase in the Company's 2015 effective tax rate (benefit rate), as compared to 2014, is primarily due to a decrease in estimated losses associated with the Kemper IGCC, offset by a decrease in non-taxable AFUDC equity. The increase in the Company's 2014 effective tax rate (benefit rate), as compared to 2013, is primarily due to an increase in non-taxable AFUDC equity. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ 165 $ 4 $ 6 Tax positions increase from current periods 32 58 — Tax positions increase/(decrease) from prior periods 224 103 (2 ) Balance at end of year $ 421 $ 165 $ 4 The tax positions increase from current periods and prior periods for 2015 and 2014 relates to deductions for R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for more information. The tax positions decrease from prior periods for 2013 relates primarily to the Company's compliance with final U.S. Treasury regulations that resulted in a tax accounting method change for repairs. The impact on the Company's effective tax rate, if recognized, is as follows: 2015 2014 2013 (in millions) Tax positions impacting the effective tax rate $ (2 ) $ 4 $ 4 Tax positions not impacting the effective tax rate 423 161 — Balance of unrecognized tax benefits $ 421 $ 165 $ 4 The tax positions impacting the effective tax rate for 2015 primarily relate to a graduated tax rate adjustment on the 2014 federal income tax return. The tax positions impacting the effective tax rate for 2014 and 2013 primarily relate to state income tax credits. The tax positions not impacting the effective tax rate for 2015 and 2014 relate to deductions for R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for more information. Accrued interest for unrecognized tax benefits was as follows: 2015 2014 2013 (in millions) Interest accrued at beginning of year $ 3 $ 1 $ 1 Interest accrued during the year 6 2 — Balance at end of year $ 9 $ 3 $ 1 The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months . The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. 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, reduced tax payments for 2015 and included in its 2013 and 2014 consolidated federal income tax returns deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and the Company believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, the Company had related unrecognized tax benefits associated with these R&E deductions of approximately $423 million and associated interest of $9 million as of December 31, 2015. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time. |
Southern Power [Member] | |
Income Tax Disclosure [Line Items] | |
INCOME TAXES | INCOME TAXES On behalf of the Company, Southern Company files a consolidated federal income tax return and 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. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current (*) $ 12 $ 179 $ (120 ) Deferred (*) 10 (166 ) 159 22 13 39 State — Current (32 ) (14 ) (5 ) Deferred 31 (2 ) 12 (1 ) (16 ) 7 Total $ 21 $ (3 ) $ 46 (*) ITCs 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 the federal income tax expense above. ITCs reclassified in this manner include $246 million for 2015 and $305 million for 2014. These ITCs 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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation and other property basis differences $ 1,364 $ 1,006 Basis difference on asset transfers 3 3 Levelized capacity revenues 22 17 Other 4 6 Total 1,393 1,032 Deferred tax assets — Federal effect of state deferred taxes 40 29 Net basis difference on federal ITCs 149 102 Alternative minimum tax carryforward 15 15 Unrealized tax credits 551 305 Unrealized loss on interest rate swaps 4 6 Levelized capacity revenues 4 5 Deferred state tax assets 13 15 Other 18 4 Total 794 481 Valuation Allowance (2 ) (8 ) Net deferred income tax assets 792 473 Accumulated deferred income taxes $ 601 $ 559 On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from deferred income taxes, current of $306 million and accrued income taxes of $2 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. Deferred tax liabilities are primarily the result of property related timing differences. The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014. Deferred tax assets consist primarily of timing differences related to net basis differences on federal ITCs and the carryforward of unrealized federal ITCs. The ITC carryforwards begin expiring in 2034, but are expected to be fully utilized by 2020. At December 31, 2015 and December 31, 2014 , the Company had state net operating loss (NOL) carryforwards of $225 million and $247 million , respectively. The NOL carryforwards resulted in deferred tax assets of $8 million as of December 31, 2015 and $9 million as of December 31, 2014 . The Company has established a valuation allowance due to the remote likelihood that the full tax benefits will be realized. During 2015 , approximately $87 million in NOLs expired resulting in a decrease in the valuation allowance for the same amount. The offsetting adjustments resulted in no tax impact. Of the NOL balance at December 31, 2015 , approximately $40 million will expire in 2017 and $185 million will expire from 2033 to 2035. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction (0.3 ) (6.0 ) 2.2 Amortization of ITC (5.0 ) (4.3 ) (1.7 ) ITC basis difference (21.5 ) (27.7 ) (14.5 ) Other 0.2 1.1 0.3 Effective income tax rate 8.4 % (1.9 )% 21.3 % The Company's effective tax rate increased in 2015 primarily due to decreased benefits from federal ITCs as compared to 2014. The Company's effective tax rate decreased in 2014 primarily due to greater benefits from federal ITCs as compared to 2013. The Company received cash related to federal ITCs under the renewable energy initiatives of $162 million in tax year 2015 , $74 million in tax year 2014 , and $158 million in tax year 2013 . The tax benefit of the related basis difference reduced income tax expense by $54 million in 2015 , $48 million in 2014 , and $31 million in 2013 . Federal ITCs amortized to income tax expense amounted to $19 million , $11 million , and $6 million in 2015, 2014, and 2013, respectively. See Note 1 under "Income and Other Taxes" for additional information. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ 5 $ 2 $ 3 Tax positions increase from current periods 9 5 2 Tax positions decrease from prior periods (6 ) (2 ) (3 ) Balance at end of year $ 8 $ 5 $ 2 The increase in unrecognized tax benefits from current periods for 2015 , 2014 and 2013 , and the decrease from prior periods in 2015 and 2014 primarily relate to federal ITCs and would each impact the Company's effective tax rate, if recognized. The decrease in unrecognized tax benefits from prior periods for 2013 relates to the Company's compliance with final U.S. Treasury regulations for the tax method change for repairs. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months . The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. 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. |
Financing
Financing | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Long-Term Debt Payable to an Affiliated Trust Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million as of December 31, 2015 and 2014 , 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, 2015 and 2014 , trust preferred securities of $200 million were outstanding. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: 2015 2014 (in millions) Senior notes $ 1,810 $ 2,375 Other long-term debt 829 775 Pollution control revenue bonds 4 152 Capitalized leases 32 31 Unamortized debt issuance expense (1 ) (4 ) Total $ 2,674 $ 3,329 Maturities through 2020 applicable to total long-term debt are as follows: $2.7 billion in 2016 ; $2.4 billion in 2017 ; $1.7 billion in 2018 ; $1.2 billion in 2019 ; and $1.4 billion in 2020 . Bank Term Loans Southern Company and certain of the traditional operating companies have entered into various floating rate bank term loan agreements for loans bearing interest based on one-month LIBOR. At December 31, 2015 , Southern Company, Mississippi Power, and Southern Power had outstanding bank term loans totaling $400 million , $900 million , and $400 million , respectively, of which $1.23 billion are reflected in the statements of capitalization as long-term debt and $475 million are reflected in the balance sheet as notes payable. At December 31, 2014 , Mississippi Power had outstanding bank term loans totaling $775 million . In September 2015, Southern Company entered into a $400 million aggregate principal amount 18 -month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes. In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million , bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million , working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. In August 2015, Southern Power Company entered into a $400 million aggregate principal amount 13 -month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes, including Southern Power's growth strategy and continuous construction program. The outstanding bank loans as of December 31, 2015 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for 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, other hybrid securities, and, for Southern Company and Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC. 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, 2015 , each of Southern Company, 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 a loan guarantee agreement (Loan Guarantee Agreement) in February 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion . All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property. Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375% . In February 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion . The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million , which are being amortized over the life of the borrowings under the FFB Credit Facility. In December 2014, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million . The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044. In June and December 2015, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million and $400 million , respectively. The interest rate applicable to the $600 million principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072% , both for an interest period that extends to 2044. Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default. In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable. In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4. Senior Notes Southern Company and its subsidiaries issued a total of $3.7 billion of senior notes in 2015 . Southern Company issued $600 million and its subsidiaries issued a total of $3.1 billion . The proceeds of these issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs, and, for Southern Power, its growth strategy. At December 31, 2015 and 2014 , Southern Company and its subsidiaries had a total of $19.1 billion and $18.2 billion , respectively, of senior notes outstanding. At December 31, 2015 and 2014 , Southern Company had a total of $2.4 billion and $2.2 billion , respectively, of senior notes outstanding. Subsequent to December 31, 2015, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of its Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes. Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred and preference stockholders of such subsidiary. Junior Subordinated Notes In October 2015, Southern Company issued $1.0 billion aggregate principal amount of Series 2015A 6.25% Junior Subordinated Notes due October 15, 2075. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes. Pollution Control Revenue Bonds Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of pollution control bonds issued by public authorities. The traditional operating companies had $3.3 billion and $3.2 billion of outstanding pollution control revenue bonds at December 31, 2015 and December 31, 2014 , respectively. The traditional operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. Plant Daniel Revenue Bonds In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See "Assets Subject to Lien" herein for additional information. Other Revenue Bonds Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities. Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2015 and 2014 . Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as utility plant in service and the related obligations are classified as long-term debt. In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2015 and 2014 of approximately $77 million and $80 million , respectively, with an annual interest rate of 4.9% for both years. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service. At December 31, 2015 and 2014 , the capitalized lease obligations for Georgia Power's corporate headquarters building were $35 million and $40 million , respectively, with an annual interest rate of 7.9% for both years. At December 31, 2015 and 2014 , Alabama Power had a capitalized lease obligation of $5 million for a natural gas pipeline with an annual interest rate of 6.9% . At December 31, 2015 and 2014 , a subsidiary of Southern Company had capital lease obligations of approximately $30 million and $34 million , respectively, for certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.2% to 3.1% . Other Obligations In 2012, January 2014, and October 2014, Mississippi Power received $150 million , $75 million , and $50 million , respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. In 2013, Southern Company entered into an agreement with SMEPA under which Southern Company agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the asset purchase agreement between Mississippi Power and SMEPA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which matures on December 1, 2017. 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, 2015 . The revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Plant Daniel Revenue Bonds" herein for additional information. See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Each of the Project Credit Facilities (defined below) is secured by the membership interests and assets of the subsidiary of Southern Power Company party to the agreement. See Note 12 under "Southern Power" for additional information. Bank Credit Arrangements At December 31, 2015 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Due Within One Year Company 2016 2017 2018 2020 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) Southern Company (a) $ — $ — $ 1,000 $ 1,250 $ 2,250 $ 2,250 $ — $ — $ — $ — Alabama Power 40 — 500 800 1,340 1,340 — — — 40 Georgia Power — — — 1,750 1,750 1,732 — — — — Gulf Power 80 30 165 — 275 275 50 — 50 30 Mississippi Power 220 — — — 220 195 30 15 45 175 Southern Power (b) — — — 600 600 566 — — — — Other 70 — — — 70 70 — — — 70 Total $ 410 $ 30 $ 1,665 $ 4,400 $ 6,505 $ 6,428 $ 80 $ 15 $ 95 $ 315 (a) Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein. (b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note 12 under "Southern Power" for additional information. As reflected in the table above, in August 2015, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restated their multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $1.25 billion from $1.0 billion and to $600 million from $500 million , respectively. Georgia Power increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1.0 billion with a maturity date of 2018. Alabama Power entered into a new $500 million three -year credit arrangement which replaced a majority of Alabama Power's bilateral credit arrangements. In November 2015, Gulf Power amended and restated certain of its multi-year credit arrangements which, among other things, extended the maturity dates for the majority of Gulf Power's agreements from 2016 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 operating companies, and Southern Power Company. 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 credit arrangements contain covenants that limit debt level to 70% of total capitalization, as defined in the agreements, and most of these other bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities, and, for Southern Company and Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC. 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, 2015 , Southern Company, the traditional operating companies, and Southern Power Company were each in compliance with their respective debt limit covenants. A portion of the $6.4 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies' pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2015 was approximately $1.8 billion . In addition, at December 31, 2015 , the traditional operating companies had approximately $181 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. The Bridge Agreement provides for total loan commitments in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments required in connection with the consummation of the Merger, the Bridge Agreement and the borrowings thereunder, the other financing transactions related to the Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loan under the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement. As of December 31, 2015, Southern Company had no outstanding loans under the Bridge Agreement. See Note 12 under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger. Southern Company, the traditional operating companies, and Southern Power Company make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2015: Commercial paper $ 740 0.7 % Short-term bank debt 500 1.4 % Total $ 1,240 0.9 % December 31, 2014: Commercial paper $ 803 0.3 % Short-term bank debt — — % Total $ 803 0.3 % In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of December 31, 2015 of $137 million at a weighted average interest rate of 2.0% . Redeemable Preferred Stock of Subsidiaries Each of the traditional operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as "noncontrolling interests," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity. At December 31, 2015 , the outstanding redeemable preferred stock of subsidiaries of Southern Company was $118 million . At December 31, 2014 and 2013 , the outstanding redeemable preferred stock of subsidiaries of Southern Company was $375 million . In May 2015, Alabama Power redeemed 6.48 million shares ( $162 million aggregate stated capital) of its 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date and 4.0 million shares ( $100 million aggregate stated capital) of its 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date. Additionally, $5 million of issuance costs were transferred from redeemable preferred stock of subsidiaries to common stockholder's equity upon redemption. |
Alabama Power [Member] | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Long-Term Debt Payable to an Affiliated Trust The Company has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million as of December 31, 2015 and 2014 , 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, 2015 and 2014 , 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, 2015 , the Company had $200 million of senior notes and pollution control revenue bonds due within one year. At December 31, 2014 , the Company had $454 million of senior notes and pollution control revenue bonds due within one year. Maturities through 2020 applicable to total long-term debt are as follows: $200 million in 2016; $562 million in 2017; $201 million in 2019; and $251 million in 2020. There are no material scheduled maturities in 2018. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control and solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2015. In April 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2015 and 2014 was $1.1 billion and $1.2 billion , respectively. Senior Notes In March 2015, the Company issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.650% Senior Notes due March 15, 2035 and for general corporate purposes, including the Company's continuous construction program. In April 2015, the Company issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used in May 2015 to redeem certain classes of the Company's preferred and preference stock plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including the Company's continuous construction program. See "Redeemable Preferred Stock" herein for additional information. At December 31, 2015 and 2014 , the Company had $5.6 billion and $5.3 billion of senior notes outstanding, respectively. As of December 31, 2015, the Company did not have any outstanding secured debt. Subsequent to December 31, 2015, the Company issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including the Company's continuous construction program. Redeemable Preferred and Preference Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary and involuntary dissolution. The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the Company's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company's board. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. The Company's preferred stock is subject to redemption at a price equal to the par value plus a premium. The Company's Class A preferred stock is subject to redemption at a price equal to the stated capital. Certain series of the Company's preference stock are subject to redemption at a price equal to the stated capital plus a make-whole premium based on the present value of the liquidation amount and future dividends to the first stated capital redemption date and the other series of preference stock are subject to redemption at a price equal to the stated capital. All series of the Company's preferred stock currently are subject to redemption at the option of the Company. Information for each outstanding series is in the table below: Preferred/Preference Stock Par Value/Stated Capital Per Share Shares Outstanding Redemption Price Per Share 4.92% Preferred Stock $100 80,000 $103.23 4.72% Preferred Stock $100 50,000 $102.18 4.64% Preferred Stock $100 60,000 $103.14 4.60% Preferred Stock $100 100,000 $104.20 4.52% Preferred Stock $100 50,000 $102.93 4.20% Preferred Stock $100 135,115 $105.00 5.83% Class A Preferred Stock $25 1,520,000 Stated Capital 6.450% Preference Stock $25 6,000,000 * 6.500% Preference Stock $25 2,000,000 * * Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital In May 2015, the Company redeemed 6.48 million shares ( $162 million aggregate stated capital) of the Company's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date and 4.0 million shares ( $100 million aggregate stated capital) of the Company's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date. Additionally, the $5 million of issuance costs were transferred from redeemable preferred stock to common stockholder's equity upon redemption. Also during May 2015, the Company redeemed 6.0 million shares ( $150 million aggregate stated capital) of the Company's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date. There were no changes for the years ended December 31, 2014 and 2013 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, 2015 , committed credit arrangements with banks were as follows: Expires Due Within One Year 2016 2018 2020 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) $ 40 $ 500 $ 800 $ 1,340 $ 1,340 $ — $ 40 As reflected in the table above, in August 2015, the Company amended and restated its multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. In September 2015, the Company entered into a new $500 million three -year credit arrangement which replaced a majority of the Company's bilateral credit arrangements. Most of the bank credit arrangements require payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1 / 10 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. 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 to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2015 , 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 program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $810 million as of December 31, 2015 . In addition, at December 31, 2015, the Company had $80 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, 2015 and 2014 , there was no short-term debt outstanding. At December 31, 2015 , the Company had regulatory approval to have outstanding up to $2.1 billion of short-term borrowings. |
Georgia Power [Member] | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Securities Due Within One Year A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows: 2015 2014 (in millions) Senior notes $ 700 $ 1,050 Pollution control revenue bonds 4 98 Capital lease 8 6 Unamortized debt issuance expense — (4 ) Total $ 712 $ 1,150 Maturities through 2020 applicable to total long-term debt are as follows: $712 million in 2016 ; $459 million in 2017 ; $761 million in 2018 ; $512 million in 2019 ; and $49 million in 2020 . Senior Notes In December 2015, the Company issued $500 million aggregate principal amount of Series 2015A 1.95% Senior Notes due December 1, 2018. The proceeds were used to repay at maturity $250 million aggregate principal amount of the Company's Series Z 5.25% Senior Notes due December 15, 2015, to repay a portion of the Company's short-term indebtedness, and for general corporate purposes, including the Company's continuous construction program. At December 31, 2015 and 2014 , the Company had $6.3 billion and $6.9 billion of senior notes outstanding, respectively. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $2.4 billion and $1.2 billion at December 31, 2015 and 2014 , respectively. As of December 31, 2015, the Company's secured debt included borrowings of $2.2 billion guaranteed by the DOE and capital lease obligations. As of December 31, 2014, the Company's secured debt was related to borrowings guaranteed by the DOE and capital lease obligations. See Note 7 for additional information. See "DOE Loan Guarantee Borrowings" herein for additional information. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2015 and 2014 was $1.8 billion and $1.6 billion , respectively. In May 2015, the Company reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013, which had been previously purchased and held by the Company since 2013. In August 2015, in connection with optional tenders, the Company repurchased and reoffered to the public $94.6 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009 and $10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013. In November 2015, the Company reoffered to the public $89.2 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009 and $46 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996, which had been previously repurchased and held by the Company since 2010. Bank Term Loans In March 2015, the Company entered into a $250 million aggregate principal amount three -month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes and the loan was repaid at maturity. DOE Loan Guarantee Borrowings Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), the Company and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) in February 2014, under which the DOE agreed to guarantee the obligations of the Company under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, the Company, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which the Company may make term loan borrowings through the FFB. Proceeds of advances made under the FFB Credit Facility are used to reimburse the Company for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion . All borrowings under the FFB Credit Facility are full recourse to the Company, and the Company is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. The Company's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) the Company's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on the Company's ability to grant liens on other property. Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375% . In February 2014, the Company made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion . The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, the Company incurred issuance costs of approximately $66 million , which are being amortized over the life of the borrowings under the FFB Credit Facility. In December 2014, the Company made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million . The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044. In June and December 2015, the Company made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million and $400 million , respectively. The interest rate applicable to the $600 million principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072% , both for an interest period that extends to 2044. Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. Under the Loan Guarantee Agreement, the Company is subject to customary borrower affirmative and negative covenants and events of default. In addition, the Company is subject to project-related reporting requirements and other project-specific covenants and events of default. In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and the Company will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. The Company also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable. In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume the Company's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of the Company's ownership interest in Plant Vogtle Units 3 and 4. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2015 and 2014, the Company had a capital lease asset for its corporate headquarters building of $61 million , with accumulated depreciation at December 31, 2015 and 2014 of $26 million and $21 million , respectively. At December 31, 2015 and 2014 , the capitalized lease obligation was $35 million and $40 million , respectively, with an annual interest rate of 7.9% for both years. For ratemaking purposes, the Georgia PSC has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. The annual expense incurred for all capital leases was not material for any year presented. At December 31, 2015, the Company had capital lease assets and corresponding obligations of $149 million and $148 million , respectively, for two affiliate PPAs that became effective in 2015. Contractual lease payments, including imputed interest, of $20 million and capital lease asset amortization of $10 million were included in purchased power, affiliates expense in 2015. The annual imputed interest rates will range from 13% to 14% for these two capital lease PPAs over their term. For ratemaking purposes, the Georgia PSC has allowed the capital lease asset amortization in cost of service and the imputed interest in the Company's cost of debt. See 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 Class A preferred stock, preference stock, and common stock outstanding. The Company's Class A preferred stock ranks senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. The outstanding series of the Class A preferred stock is subject to redemption at the option of the Company at any time at a redemption price equal to 100% of the par value. In addition, on or after October 1, 2017, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the par value. With respect to any redemption of the preference stock prior to October 1, 2017, the redemption price includes a make-whole premium based on the present value of the liquidation amount and future dividends through the first par redemption date. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Bank Credit Arrangements At December 31, 2015, the Company had a $1.75 billion committed credit arrangement with banks, of which $1.73 billion was unused. These credit arrangements expire in 2020. In August 2015, the Company amended and restated its multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. The Company increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016. 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. 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. The 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. 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 its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2015 was $872 million . In addition, at December 31, 2015, the Company had $69 million of fixed rate 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 arrangements described above. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. 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, 2015: Commercial paper $ 158 0.6 % December 31, 2014: Commercial paper $ 156 0.3 % |
Gulf Power [Member] | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Securities Due Within One Year At December 31, 2015 , the Company had $110 million of long-term debt due within one year. Maturities from 2017 through 2020 applicable to total long-term debt are as follows: $85 million in 2017 and $175 million in 2020. There are no scheduled maturities in 2018 or 2019. Senior Notes At each of December 31, 2015 and 2014 , the Company had a total of $1.01 billion and $1.07 billion 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, 2015 and 2014. In September 2015, the Company redeemed $60 million aggregate principal amount of Series L 5.65% Senior Notes due September 1, 2035. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2015 and 2014 was $309 million . In July 2015, the Company purchased and held $13 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds (Gulf Power Company Project), Series 2012. The Company remarketed these bonds to the public on July 16, 2015. Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2015 . The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the preference stock. In addition, certain series of the preference stock may be redeemed earlier at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends. In January 2015, the Company issued 200,000 shares of common stock to Southern Company and realized proceeds of $20 million . The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Assets Subject to Lien The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2015 . 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, 2015 , committed credit arrangements with banks were as follows: Expires Executable Term-Loans Due Within One Year 2016 2017 2018 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $ 80 $ 30 $ 165 $ 275 $ 275 $ 50 $ — $ 50 $ 30 In November 2015, the Company amended and restated certain of its multi-year credit arrangements which, among other things, extended the maturity dates for the majority of the Company's agreements from 2016 to 2018. 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, 2015 , the Company was in compliance with these covenants. Most of the $275 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, 2015 was approximately $82 million . In addition, at December 31, 2015, the Company had $33 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 in the balance sheets. Details of short-term borrowings were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2015 $ 142 0.7% December 31, 2014 $ 110 0.3% |
Mississippi Power [Member] | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Bank Term Loans In April 2015, the Company entered into two short-term floating rate bank loans with a maturity date of April 1, 2016 in an aggregate principal amount of $475 million bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million , working capital, and other general corporate purposes, including the Company’s ongoing construction program. The Company also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. At December 31, 2015 , the Company had a total of $900 million in bank loans outstanding including $475 million classified as notes payable and $425 million classified as securities due within one year. At December 31, 2014, the Company had $775 million in bank loans outstanding which are classified as securities due within one year. These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, other hybrid securities, and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2015 , the Company was in compliance with its debt limits. Senior Notes At December 31, 2015 and 2014 , the Company had $1.1 billion of senior notes outstanding. These senior notes are effectively subordinated to the secured debt of the Company. See "Plant Daniel Revenue Bonds" below for additional information regarding the Company's secured indebtedness. Plant Daniel Revenue Bonds In 2011, in connection with the Company's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, the Company assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. These bonds are secured by Plant Daniel Units 3 and 4 and certain related personal property. The bonds were recorded at fair value as of the date of assumption, or $346 million , reflecting a premium of $76 million . See "Assets Subject to Lien" herein for additional information. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2015 and 2014 was as follows: 2015 2014 (in millions) Senior notes $ 300 $ — Bank term loans 425 775 Capitalized leases 3 3 Outstanding at December 31 $ 728 $ 778 Maturities through 2020 applicable to total long-term debt are as follows: $728 million in 2016, $614 million in 2017, $3 million in 2018, $128 million in 2019, and $10 million in 2020. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2015 and 2014 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 IGCC and related facilities. The Company had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2015 and 2014 . Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. Capital Leases In 2013, the Company entered into an agreement to sell the air separation unit for the Kemper IGCC and also entered into a 20 -year nitrogen supply agreement. The nitrogen supply agreement was determined to be a sale/leaseback agreement which resulted in a capital lease obligation at December 31, 2015 and 2014 of $77 million and $80 million , respectively, with an annual interest rate of 4.9% for both years. There are no contingent rentals in the contract and a portion of the monthly payment specified in the agreement is related to executory costs for the operation and maintenance of the air separation unit and excluded from the minimum lease payments. The minimum lease payments for 2015 were $7 million and will be $7 million each year thereafter. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service. Other Obligations In June 2015, the Company issued an 18 -month floating rate promissory note to Southern Company bearing interest based on LIBOR plus 1.25% . This note was for an aggregate principal amount of approximately $301 million , the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposits. In December 2015, the $301 million promissory note was amended, which among other things, changed the maturity date to December 1, 2017 and changed the interest rate to be based on one-month LIBOR plus 1.50% . See Note 3 under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" for additional information. In November 2015, the Company issued a 25 -month floating rate promissory note to Southern Company bearing interest based on an adjusted LIBOR rate. At December 31, 2015, the adjusted LIBOR rate was equal to the one-month LIBOR plus 1.50% . This note was for an aggregate principal amount of up to $375 million . As of December 31, 2015 the Company had borrowed $275 million . 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. 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 $ 25 1,200,000 $ 25.00 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, 2015 , committed credit arrangements with banks were as follows: Expires Executable Term-Loans Due Within One Year 2016 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $220 $220 $195 $30 $15 $45 $175 Subject to applicable market conditions, the Company expects to renew its bank credit arrangements, as needed, prior to expiration. Most of these bank credit arrangements require payment of commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. Most of these bank credit arrangements contain covenants that limit the Company's debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. A portion of the $195 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, 2015 was $40 million . At December 31, 2015 and 2014 , there was no commercial paper debt outstanding. At December 31, 2015, there was $500 million of short-term debt outstanding. At December 31, 2014, there was no short-term debt outstanding. |
Southern Power [Member] | |
Debt Disclosure [Line Items] | |
FINANCING | FINANCING Southern Power Company's senior notes and credit facility are unsecured senior debt securities, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company. The senior notes and credit facility are subordinated to any future secured debt and any potential claims of creditors of Southern Power Company's subsidiaries. As of December 31, 2015 , the company had no secured debt at its subsidiaries other than the three secured project credit facilities, which are discussed below. Securities Due Within One Year At December 31, 2015 and 2014, the Company had a $400 million bank loan and $525 million of senior notes due within one year, respectively. In addition, at December 31, 2015 , the Company classified as due within one year approximately $3 million of long-term notes payable to TRE that are expected to be repaid in 2016. Maturities through 2020 applicable to total long-term debt are as follows: $500 million in 2017, $350 million in 2018, and $300 million in 2020. Other Long-Term Notes During 2015 , the Company prepaid $4 million of long-term notes payable to TRE and issued $2 million due September 30, 2035 under a promissory note related to the financing of Morelos. At December 31, 2015 and 2014 , the Company had $13 million and $19 million , respectively, of long-term notes payable to TRE. In August 2015, the Company entered into a $400 million aggregate principal amount 13 -month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes, including the Company's growth strategy and continuous construction program. This bank 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 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, 2015 , the Company was in compliance with its debt limits. Senior Notes In May 2015, the Company issued $350 million aggregate principal amount of its Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including the Company’s growth strategy and continuous construction program, and for a portion of the repayment at maturity of $525 million aggregate principal amount of the Company's 4.875% Senior Notes on July 15, 2015. In November 2015, the Company issued $500 million aggregate principal amount of its Series 2015C 4.15% Senior Notes due December 1, 2025 and $500 million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017. The proceeds will be used for renewable energy generation projects. At December 31, 2015 and 2014 , the Company had $2.7 billion and $1.6 billion of senior notes outstanding, respectively, which included senior notes due within one year. Bank Credit Arrangements Company Facility In August 2015, the Company amended and restated its multi-year credit facility (Facility). This amendment extended among other things the maturity date from 2018 to 2020. The Company also increased its borrowing ability under the Facility to $600 million from $500 million . As of December 31, 2015 , the total amount available under the Facility was $566 million . As of December 31, 2014 , the total amount available under the previous $500 million facility was $488 million . The amounts outstanding as of December 31, 2015 and 2014 reflect $34 million and $12 million in letters of credit, respectively. The Facility does not contain a material adverse change clause at the time of borrowing. Subject to applicable market conditions, the Company plans to renew or replace the Facility prior to expiration. 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, 2015 , the Company was in compliance with its debt limits. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. Subsidiary Project Credit Facilities In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of the Company, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility and is secured by the membership interests of project companies. Proceeds from the Project Credit Facilities are being used to finance project costs related to the solar facility currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of December 31, 2015 . Project Maturity Date Construction Loan Facility Bridge Loan Facility Total Total Undrawn Letter of Credit Facility Total Undrawn (in millions) Tranquillity Earlier of COD or December 31, 2016 $ 86 $ 172 $ 258 $ 147 $ 77 $ 26 Roserock Earlier of COD or November 30, 2016 63 180 243 243 23 23 Garland Earlier of COD or November 30, 2016 86 308 394 368 49 32 Total $ 235 $ 660 $ 895 $ 758 $ 149 $ 81 The total amount outstanding on the Project Credit Facilities as of December 31, 2015 was $137 million at a weighted average interest rate of 2.0% and is included in notes payable in the balance sheet. The Company expects to repay these Project Credit Facilities from its traditional sources of capital upon their maturity. Commercial Paper Program The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. Commercial paper is included in notes payable in the balance sheets as noted below: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2015 $ — N/A December 31, 2014 $ 195 0.4 % Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2015 | |
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 2015 , 2014 , and 2013 , the traditional operating companies and Southern Power incurred fuel expense of $4.8 billion , $6.0 billion , and $5.5 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 $227 million , $198 million , and $157 million for 2015 , 2014 , and 2013 , respectively. Estimated total obligations under these commitments at December 31, 2015 were as follows: Operating Leases (*) Other (in millions) 2016 $ 233 $ 10 2017 242 8 2018 246 7 2019 249 8 2020 246 4 2021 and thereafter 1,291 47 Total $ 2,507 $ 84 (*) A total of $304 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. Operating Leases The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $130 million , $118 million , and $123 million for 2015 , 2014 , and 2013 , respectively. Southern Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. As of December 31, 2015 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2016 $ 40 $ 81 $ 121 2017 25 78 103 2018 14 67 81 2019 6 55 61 2020 6 47 53 2021 and thereafter 16 690 706 Total $ 107 $ 1,018 $ 1,125 For the traditional operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $48 million . At the termination of the leases, the lessee may renew the lease or exercise its purchase option or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. Guarantees In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years . The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million . As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees. |
Alabama Power [Member] | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Fuel and Purchased Power Agreements To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2015, 2014, and 2013, the Company incurred fuel expense of $1.3 billion , $1.6 billion , and $1.6 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 $38 million , $37 million , and $30 million for 2015, 2014, and 2013, respectively. Total estimated minimum long-term obligations at December 31, 2015 were as follows: Operating Lease PPAs (in millions) 2016 $ 39 2017 40 2018 41 2019 43 2020 44 2021 and thereafter 93 Total commitments $ 300 SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases The Company has entered into rental agreements for coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense was $19 million in 2015 , $18 million in 2014 , and $21 million in 2013 . Of these amounts, $13 million , $14 million , and $18 million for 2015, 2014, and 2013, respectively, relate to the railcar leases and are recoverable through the Company's Rate ECR. As of December 31, 2015, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Vehicles & Other Total (in millions) 2016 $ 13 $ 6 $ 19 2017 8 5 13 2018 5 4 9 2019 5 4 9 2020 5 4 9 2021 and thereafter 13 — 13 Total $ 49 $ 23 $ 72 In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases have terms expiring through 2023 with maximum obligations under these leases of $4 million in 2016 and $12 million in 2021 and thereafter. There are no obligations under these leases in 2017, 2018, 2019, and 2020. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations. Guarantees The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4 for additional information. |
Georgia Power [Member] | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Fuel and Purchased Power Agreements To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2015, 2014, and 2013, the Company incurred fuel expense of $2.0 billion , $2.5 billion , and $2.3 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. On December 15, 2015, the Company's natural gas hedging program was revised and approved by the Georgia PSC. 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 $10 million , $19 million , and $27 million in 2015, 2014, and 2013, 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 $203 million , $167 million , and $162 million for 2015, 2014, and 2013, respectively. Estimated total long-term obligations at December 31, 2015 were as follows: Affiliate Capital Leases Affiliate Operating Leases Non-Affiliate Operating Leases (4) Vogtle Units 1 and 2 Capacity Payments Total ($) (in millions) 2016 $ 22 $ 99 $ 115 $ 10 $ 246 2017 22 71 123 8 224 2018 22 62 126 7 217 2019 23 63 127 8 221 2020 23 64 123 4 214 2021 and thereafter 227 538 1,007 47 1,819 Total $ 339 $ 897 $ 1,621 $ 84 $ 2,941 Less: amounts representing executory costs (1) 54 Net minimum lease payments 285 Less: amounts representing interest (2) 84 Present value of net minimum lease payments (3) $ 201 (1) Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) a re estimated and included in total minimum lease payments. (2) Amount necessary to reduce minimum lease payments to present value calculated at the Company's incremental borrowing rate at the inception of the leases. (3) Once service commenced under the PPAs beginning in 2015, the Company recognized capital lease assets and capital lease obligations totaling $149 million , being the lesser of the estimated fair value of the lease property or the present value of the net minimum lease payments. (4) A total of $304 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases In addition to the PPA operating leases discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $29 million for 2015 , $28 million for 2014 , and $32 million for 2013 . The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments. As of December 31, 2015, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Other Total (in millions) 2016 $ 15 $ 8 $ 23 2017 10 8 18 2018 5 7 12 2019 1 7 8 2020 1 6 7 2021 and thereafter 3 13 16 Total $ 35 $ 49 $ 84 Railcar minimum lease payments are disclosed at 100% of railcar lease obligations; however, a portion of these obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the railcar leases are recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates. In addition to the above rental commitments, the Company has obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $32 million . At the termination of the leases, the lessee may either renew the lease, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations. Guarantees Alabama Power has guaranteed the obligations of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019 and also $100 million of senior notes issued in November 2013, which mature in December 2018. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. See Note 4 for additional information. In addition, in 2013, the Company entered into an agreement that requires the Company to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years . The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million . As discussed earlier in this Note under "Operating Leases," the Company has entered into certain residual value guarantees related to railcar leases. |
Gulf Power [Member] | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Fuel and Purchased Power Agreements To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2015 , 2014 , and 2013 , the Company incurred fuel expense of $445 million , $605 million , and $533 million , respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. In addition, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission, some of which are accounted for as operating leases. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity and transmission-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Capacity expense under purchased power agreements accounted for as operating leases was $75 million , $50 million , and $21 million for 2015 , 2014 , and 2013 , respectively. Estimated total minimum long-term commitments at December 31, 2015 were as follows: Operating Lease PPAs (in millions) 2016 $ 79 2017 79 2018 79 2019 79 2020 79 2021 and thereafter 191 Total $ 586 SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases In addition to the operating lease PPAs discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $14 million , $15 million , and $18 million for 2015 , 2014 , and 2013 , respectively. Estimated total minimum lease payments under these operating leases at December 31, 2015 were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2016 $ 9 $ 1 $ 10 2017 6 1 7 2018 4 — 4 Total $ 19 $ 2 $ 21 The Company and Mississippi Power jointly entered into an operating lease agreement for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of the lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options. The Company's share of the lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, was $2 million in 2015 , and $3 million in both 2014 and 2013 . The Company's annual railcar lease payments for 2016 and 2017 will average approximately $1 million each year. There are no lease payment obligations for the period 2018 and thereafter. In addition to railcar leases, the Company has operating lease agreements for barges and towboats for the transport of coal to Plants Crist and Smith. 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 $10 million in both 2015 and 2014 and $12 million in 2013. The Company's annual barge and towboat payments for 2016 through 2018 will average approximately $5 million each year. |
Mississippi Power [Member] | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Fuel and Purchased Power Agreements To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2015 , 2014 , and 2013 , the Company incurred fuel expense of $443 million , $574 million , and $491 million , respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. Coal commitments include a management fee associated with a 40 -year management contract with Liberty Fuels related to the Kemper IGCC with the remaining amount as of December 31, 2015 of $38 million . Additional commitments for fuel will be required to supply the Company's future needs. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $5 million , $10 million , and $10 million for 2015 , 2014 , and 2013 , respectively. The Company and Gulf Power have jointly entered into operating lease agreements for aluminum railcars for the transportation of coal at Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of the lease term. The Company has one remaining operating lease which has 229 aluminum railcars. The Company and Gulf Power also have separate lease agreements for other railcars that do not contain a purchase option. The Company's share ( 50% ) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $2 million in 2015 , $3 million in 2014 , and $3 million in 2013 . The Company's annual railcar lease payments for 2016 through 2017 will average approximately $1 million . The Company has no lease obligations for the period 2018 and thereafter. In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson. The Company's share ( 50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense annually from 2013 through 2015 ; however, those amounts were immaterial for the reporting period. The Company's annual lease payments through 2020 are expected to be immaterial for fuel handling equipment. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $2 million in 2015 , $8 million in 2014 , and $7 million in 2013 related to barges and tow/shift boats. The Company has no future lease commitments with respect to these barge transportation leases. |
Southern Power [Member] | |
Commitments [Line Items] | |
COMMITMENTS | COMMITMENTS Fuel Agreements SCS, as agent for the Company and the traditional operating companies, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities which are not recognized on the Company's balance sheets. In 2015 , 2014 , and 2013 , the Company incurred fuel expense of $441 million , $596 million , and $474 million , respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and Southern Company's traditional operating companies. Under these agreements, each of the traditional operating companies and the Company may be jointly and severally liable. Southern Company has entered into keep-well agreements with each of the traditional operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements. Operating Leases The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $7 million , $4 million , and $2 million for 2015 , 2014 , and 2013 , respectively. These amounts include contingent rent expense related to a land lease based on escalation in the Consumer Price Index for All Urban Consumers. The Company includes step rents, 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, 2015 , estimated minimum lease payments under operating leases were $11 million in 2016 , $12 million in 2017 , $12 million in 2018 , $12 million in 2019 , $13 million in 2020 , and $595 million in 2021 and thereafter. The majority of the committed future expenditures are related to land leases for solar and wind facilities. Redeemable Noncontrolling Interests TRE can require the Company to purchase its redeemable noncontrolling interests in STR, which owns various solar facilities contracted under long-term PPAs, at fair market value pursuant to the partnership agreement. As of December 31, 2015 , the redeemable noncontrolling interests were $43 million . See Note 10 for additional information. |
Common Stock and Stock Compensa
Common Stock and Stock Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Class of Stock [Line Items] | |
COMMON STOCK | COMMON STOCK Stock Issued During 2015 , Southern Company issued approximately 6.6 million shares of common stock primarily through the Omnibus Incentive Compensation Plan and received proceeds of approximately $256 million . During the first nine months of 2015, all sales under the Southern Investment Plan and the Employee Savings Plan were funded with shares acquired on the open market by independent plan administrators. In October 2015, Southern Company began issuing shares of common stock through the Southern Investment Plan and the Employee Savings Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators. On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises, until December 31, 2017. Repurchases may be made by means of open market purchases, privately negotiated transactions, or accelerated or other share repurchase programs, in accordance with applicable securities laws. Under this program, approximately 2.6 million shares were repurchased in 2015 at a total cost of approximately $115 million . No further repurchases under the program are anticipated. Shares Reserved At December 31, 2015 , a total of 106 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below). Of the total 106 million shares reserved, there were 14 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2015 . Stock-Based Compensation Stock-based compensation, in the form of stock options and performance share 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. As of December 31, 2015 , there were 5,405 current and former employees participating in the stock option and performance share unit programs. Stock Options Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three -year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units. The estimated fair values of stock options granted were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 2014 2013 Expected volatility 14.6% 16.6% Expected term (in years) 5 5 Interest rate 1.5% 0.9% Dividend yield 4.9% 4.4% Weighted average grant-date fair value $2.20 $2.93 Southern Company's activity in the stock option program for 2015 is summarized below: Shares Subject to Option Weighted Average Exercise Price Outstanding at December 31, 2014 39,929,319 $40.55 Exercised 4,032,729 36.84 Cancelled 146,684 42.31 Outstanding at December 31, 2015 35,749,906 $40.96 Exercisable at December 31, 2015 25,857,590 $40.53 The number of stock options vested, and expected to vest in the future, as of December 31, 2015 was not significantly different from the number of stock options outstanding at December 31, 2015 as stated above. As of December 31, 2015 , the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and the aggregate intrinsic value for the options outstanding and options exercisable was $209 million and $162 million , respectively. For the years ended December 31, 2015 , 2014 , and 2013 , total compensation cost for stock option awards recognized in income was $6 million , $27 million , and $25 million , respectively, with the related tax benefit also recognized in income of $2 million , $10 million , and $10 million , respectively. As of December 31, 2015 , the total unrecognized compensation cost related to stock option awards not yet vested was immaterial. The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 , and 2013 was $48 million , $125 million , and $77 million , respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $19 million , $48 million , and $30 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2015 , 2014 , and 2013 was $154 million , $400 million , and $204 million , respectively. Performance Share Units From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three -year performance period which equates to the requisite service period for accounting purposes. 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. The performance goal for all performance share units issued from 2010 through 2014 was 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. For these performance share units, at the end of three years , active employees receive shares based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. 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. Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative 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 EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, 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. The TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee. 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 was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the 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 2015 2014 2013 Expected volatility 12.9% 12.6% 12.0% Expected term (in years) 3 3 3 Interest rate 1.0% 0.6% 0.4% Annualized dividend rate (*) N/A $2.03 $1.96 Weighted average grant-date fair value $46.38 $37.54 $40.50 (*) Beginning in 2015, cash dividends paid on Southern Company's common stock are accumulated and payable in additional shares of Southern Company's common stock at the end of the three-year performance period and are embedded in the grant date fair value which equates to the grant date stock price. Total unvested performance share units outstanding as of December 31, 2014 were 1,830,381 . During 2015 , 1,542,653 performance share units were granted, 812,740 performance share units were vested, and 79,902 performance share units were forfeited, resulting in 2,480,392 unvested performance share units outstanding at December 31, 2015 . In January 2016 , based on achievement of the TSR performance goal, a portion of the performance share award units granted in 2013 vested and 227,515 shares were issued at a share price of $46.80 for the three -year performance and vesting period ended December 31, 2015 . For the years ended December 31, 2015 , 2014 , and 2013 , total compensation cost for performance share units recognized in income was $88 million , $33 million , and $31 million , respectively, with the related tax benefit also recognized in income of $34 million , $13 million , and $12 million , respectively. As of December 31, 2015 , there was $33 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 19 months . Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows: Average Common Stock Shares 2015 2014 2013 (in millions) As reported shares 910 897 877 Effect of options and performance share award units 4 4 4 Diluted shares 914 901 881 Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 1 million and 7 million as of December 31, 2015 and 2014 , respectively. Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2015 , consolidated retained earnings included $7.0 billion of undistributed retained earnings of the subsidiaries. |
Alabama Power [Member] | |
Class of Stock [Line Items] | |
STOCK COMPENSATION | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation, in the form of Southern Company stock options and performance share 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. As of December 31, 2015 , there were 881 current and former employees participating in the stock option and performance share unit programs. Stock Options Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three -year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units. For the years ended December 31, 2014 and 2013, employees of the Company were granted stock options for 2,027,298 shares and 1,319,038 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93 , respectively. The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015 , the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 , and 2013 was $8 million , $21 million , and $11 million , respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $3 million , $8 million , and $4 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , the aggregate intrinsic value for the options outstanding and options exercisable was $33 million and $26 million , respectively. Performance Share Units From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three -year performance period which equates to the requisite service period for accounting purposes. 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. The performance goal for all performance share units issued from 2010 through 2014 was 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. For these performance share units, at the end of three years , active employees receive shares based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. 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. Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on 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 EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, 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. The TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee. 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, 2015 , 2014 , and 2013, employees of the Company were granted performance share units of 214,709 , 176,070 , and 141,355 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015, 2014, and 2013, 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 $46.42 , $37.54 , and $40.50 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2015 was $47.78 . For the years ended December 31, 2015 , 2014 , and 2013, total compensation cost for performance share units recognized in income was $13 million , $5 million , and $5 million , respectively, with the related tax benefit also recognized in income of $5 million , $2 million , and $2 million , respectively. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015 , there was $4 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 19 months . |
Georgia Power [Member] | |
Class of Stock [Line Items] | |
STOCK COMPENSATION | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation, in the form of Southern Company stock options and performance share 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. As of December 31, 2015 , there were 1,002 current and former employees participating in the stock option and performance share unit programs. Stock Options Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three -year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units. For the years ended December 31, 2014 and 2013, employees of the Company were granted stock options for 2,034,150 shares and 1,509,662 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93 , respectively. The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015 , the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 , and 2013 was $9 million , $19 million , and $16 million , respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $4 million , $7 million , and $6 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , the aggregate intrinsic value for the options outstanding and options exercisable was $45 million and $38 million , respectively. Performance Share Units From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three -year performance period which equates to the requisite service period for accounting purposes. 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. The performance goal for all performance share units issued from 2010 through 2014 was 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. For these performance share units, at the end of three years , active employees receive shares based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. 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. Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on 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 EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, 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. The TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee. 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, 2015, 2014, and 2013, employees of the Company were granted performance share units of 236,804 , 176,224 , and 161,240 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015, 2014, and 2013, 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 $46.41 , $37.54 , and $40.50 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2015 was $47.78 . For the years ended December 31, 2015 , 2014 , and 2013 , total compensation cost for performance share units recognized in income was $15 million , $6 million , and $6 million , respectively, with the related tax benefit also recognized in income of $6 million , $2 million , and $2 million , respectively. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015 , there was $4 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 19 months . |
Gulf Power [Member] | |
Class of Stock [Line Items] | |
STOCK COMPENSATION | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation, in the form of Southern Company stock options and performance share 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. As of December 31, 2015 , there were 198 current and former employees participating in the stock option and performance share unit programs. Stock Options Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three -year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units. For the years ended December 31, 2014 and 2013 , employees of the Company were granted stock options for 432,371 shares and 285,209 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93 , respectively. The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015 , the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 , and 2013 was $2 million , $5 million , and $2 million , respectively. 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, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , the aggregate intrinsic value for the options outstanding and options exercisable was $7 million and $5 million , respectively. Performance Share Units From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three -year performance period which equates to the requisite service period for accounting purposes. 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. The performance goal for all performance share units issued from 2010 through 2014 was 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. For these performance share units, at the end of three years , active employees receive shares based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. 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. Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on 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 EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, 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. The TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee. 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, 2015 , 2014 , and 2013 , employees of the Company were granted performance share units of 48,962 , 37,829 , and 30,627 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015 , 2014 , and 2013 , 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 $46.38 , $37.54 , and $40.50 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2015 was $47.75 . For the years ended December 31, 2015 , 2014 , and 2013 , total compensation cost for performance share units recognized in income was $2 million , $1 million , and $1 million , respectively. The related tax benefit also recognized in income was $1 million in 2015 and immaterial in 2014 and 2013. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015 , there was $2 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 19 months . |
Mississippi Power [Member] | |
Class of Stock [Line Items] | |
STOCK COMPENSATION | STOCK COMPENSATION Stock-Based Compensation Stock-based compensation, in the form of Southern Company stock options and performance share 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. As of December 31, 2015 , there were 231 current and former employees participating in the stock option and performance share unit programs. Stock Options Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three -year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units. For the years ended December 31, 2014 and 2013 , employees of the Company were granted stock options for 578,256 shares and 345,830 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93 , respectively. The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015 , the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 , and 2013 was $3 million , $5 million , and $3 million , respectively. 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, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , the aggregate intrinsic value for the options outstanding and options exercisable was $7 million and $5 million , respectively. Performance Share Units From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three -year performance period which equates to the requisite service period for accounting purposes. 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. The performance goal for all performance share units issued from 2010 through 2014 was 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. For these performance share units, at the end of three years , active employees receive shares based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. 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. Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on 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 EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, 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. The TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee. 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, 2015 , 2014 , and 2013 , employees of the Company were granted performance share units of 53,909 , 49,579 , and 36,769 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015 , 2014 , and 2013 , 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 $46.41 , $37.54 , and $40.50 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2015 was $47.77 . For the years ended December 31, 2015 , 2014 , and 2013 , total compensation cost for performance share units recognized in income was $4 million , $2 million , and $2 million , respectively, with the related tax benefit also recognized in income of $2 million , $1 million , and $1 million , respectively. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015 , there was $1 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 19 months . |
Nuclear Insurance
Nuclear Insurance | 12 Months Ended |
Dec. 31, 2015 | |
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 $13.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million , respectively, per incident, but not more than an aggregate of $38 million and $37 million , respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years . The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements. Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks , with a maximum per occurrence per unit limit of $490 million . After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years . Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $55 million and $84 million , respectively. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. |
Alabama Power [Member] | |
Nuclear Insurance [Line Items] | |
NUCLEAR INSURANCE | NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $13.5 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $255 million per incident but not more than an aggregate of $38 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years . The next scheduled adjustment is due no later than September 10, 2018. The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks , with a maximum per occurrence per unit limit of $490 million . After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years . The Company purchases limits based on the projected full cost of replacement power and has elected a 12-week deductible waiting period. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $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 [Member] | |
Nuclear Insurance [Line Items] | |
NUCLEAR INSURANCE | NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Hatch and Plant Vogtle Units 1 and 2. The Act provides funds up to $13.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests in all licensed reactors, is $247 million , per incident, but not more than an aggregate of $37 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years . The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements. The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks , with a maximum per occurrence per unit limit of $490 million . After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years . The Company purchases limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $84 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, 2015 | |
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, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 7 $ — $ — $ 7 Interest rate derivatives — 22 — — 22 Nuclear decommissioning trusts:(*) Domestic equity 541 69 — — 610 Foreign equity 47 160 — — 207 U.S. Treasury and government agency securities — 152 — — 152 Municipal bonds — 64 — — 64 Corporate bonds 11 278 — — 289 Mortgage and asset backed securities — 145 — — 145 Private equity — — — 17 17 Other 16 9 — — 25 Cash equivalents 790 — — — 790 Other investments 9 — 1 — 10 Total $ 1,414 $ 906 $ 1 $ 17 $ 2,338 Liabilities: Energy-related derivatives $ — $ 220 $ — $ — $ 220 Interest rate derivatives — 30 — — 30 Total $ — $ 250 $ — $ — $ 250 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 13 $ — $ — $ 13 Interest rate derivatives — 8 — — 8 Nuclear decommissioning trusts:(*) Domestic equity 583 85 — — 668 Foreign equity 34 184 — — 218 U.S. Treasury and government agency securities — 130 — — 130 Municipal bonds — 62 — — 62 Corporate bonds — 299 — — 299 Mortgage and asset backed securities — 139 — — 139 Private equity — — — 3 3 Other 11 13 — — 24 Cash equivalents 397 — — — 397 Other investments 9 — 1 — 10 Total $ 1,034 $ 933 $ 1 $ 3 $ 1,971 Liabilities: Energy-related derivatives $ — $ 201 $ — $ — $ 201 Interest rate derivatives — 24 — — 24 Total $ — $ 225 $ — $ — $ 225 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter 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 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. "Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions. Southern Company early adopted ASU 2015-07 effective December 31, 2015. As required, disclosures in the paragraphs and tables below are limited to only those investments in funds that are measured at net asset value as a practical expedient. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. As of December 31, 2015 and 2014 , 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, 2015 $ 17 $ 28 Not Applicable Not Applicable As of December 31, 2014 $ 3 $ 7 Not Applicable Not Applicable Private equity funds include a fund-of-funds that invests in high quality private equity funds across several market sectors, a fund that invests 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 ten years . As of December 31, 2015 and 2014 , 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: 2015 $ 27,216 $ 27,913 2014 $ 23,814 $ 25,816 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, and Southern Power. |
Alabama Power [Member] | |
Fair Value Disclosures [Line Items] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • Level 1 consists of observable market data in an active market for identical assets or liabilities. • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. • Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2015, 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, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 1 $ — $ — $ 1 Nuclear decommissioning trusts: (*) Domestic equity 359 68 — — 427 Foreign equity 47 47 — — 94 U.S. Treasury and government agency securities — 27 — — 27 Corporate bonds 11 135 — — 146 Mortgage and asset backed securities — 18 — — 18 Private equity — — — 17 17 Other — 5 — — 5 Cash equivalents 68 — — — 68 Total $ 485 $ 301 $ — $ 17 $ 803 Liabilities: Interest rate derivatives $ — $ 15 $ — $ — $ 15 Energy-related derivatives — 55 — — 55 Total $ — $ 70 $ — $ — $ 70 (*) 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, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 1 $ — $ — $ 1 Nuclear decommissioning trusts: (*) Domestic equity 403 83 — — 486 Foreign equity 34 63 — — 97 U.S. Treasury and government agency securities — 34 — — 34 Corporate bonds — 111 — — 111 Mortgage and asset backed securities — 18 — — 18 Private equity — — — 3 3 Other — 5 — — 5 Cash equivalents 162 — — — 162 Total $ 599 $ 315 $ — $ 3 $ 917 Liabilities: Interest rate derivatives $ — $ 8 $ — $ — $ 8 Energy-related derivatives — 53 — — 53 Total $ — $ 61 $ — $ — $ 61 (*) 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 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 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. The Company early adopted ASU 2015-07 effective December 31, 2015. As required, disclosures in the paragraphs and table below are limited to only those investments in funds that are measured at net asset value as a practical expedient. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. As of December 31, 2015 and 2014 , 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, 2015 $ 17 $ 28 Not Applicable Not Applicable As of December 31, 2014 $ 3 $ 7 Not Applicable Not Applicable Private equity funds include a fund-of-funds that invests in high quality private equity funds across several market sectors, a fund that invests 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 ten years . As of December 31, 2015 and 2014 , 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: 2015 $ 6,849 $ 7,192 2014 $ 6,586 $ 7,321 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 [Member] | |
Fair Value Disclosures [Line Items] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • Level 1 consists of observable market data in an active market for identical assets or liabilities. • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. • Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 2 $ — $ 2 Interest rate derivatives — 5 — 5 Nuclear decommissioning trusts:(*) Domestic equity 182 1 — 183 Foreign equity — 113 — 113 U.S. Treasury and government agency securities — 125 — 125 Municipal bonds — 64 — 64 Corporate bonds — 143 — 143 Mortgage and asset backed securities — 127 — 127 Other 16 4 — 20 Cash equivalents 63 — — 63 Total $ 261 $ 584 $ — $ 845 Liabilities: Energy-related derivatives $ — $ 15 $ — $ 15 Interest rate derivatives — 6 — 6 Total $ — $ 21 $ — $ 21 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 7 $ — $ 7 Interest rate derivatives — 6 — 6 Nuclear decommissioning trusts:(*) Domestic equity 180 2 — 182 Foreign equity — 121 — 121 U.S. Treasury and government agency securities — 96 — 96 Municipal bonds — 62 — 62 Corporate bonds — 188 — 188 Mortgage and asset backed securities — 121 — 121 Other 11 8 — 19 Total $ 191 $ 611 $ — $ 802 Liabilities: Energy-related derivatives $ — $ 27 $ — $ 27 Interest rate derivatives — 14 — 14 Total $ — $ 41 $ — $ 41 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter 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 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. The Company early adopted ASU 2015-07 effective December 31, 2015 on a retrospective basis. The guidance removed certain disclosures required for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. As of December 31, 2015 and 2014, the Company had no investments measured at net asset value as a practical expedient. As of December 31, 2015 and 2014 , 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: 2015 $ 10,145 $ 10,480 2014 $ 9,673 $ 10,552 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 [Member] | |
Fair Value Disclosures [Line Items] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • Level 1 consists of observable market data in an active market for identical assets or liabilities. • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. • Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Interest rate derivatives $ — $ 1 $ — $ 1 Cash equivalents 18 — — 18 Total $ 18 $ 1 $ — $ 19 Liabilities: Energy-related derivatives $ — $ 100 $ — $ 100 As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 18 $ — $ — $ 18 Liabilities: Energy-related derivatives $ — $ 72 $ — $ 72 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, 2015 and 2014 , 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: 2015 $ 1,303 $ 1,339 2014 $ 1,362 $ 1,477 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 [Member] | |
Fair Value Disclosures [Line Items] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • Level 1 consists of observable market data in an active market for identical assets or liabilities. • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. • Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 52 $ — $ — $ 52 Liabilities: Energy-related derivatives $ — $ 47 $ — $ 47 As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 115 $ — $ — $ 115 Liabilities: Energy-related derivatives $ — $ 45 $ — $ 45 Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for foreign currency derivatives are from observable market sources. See Note 10 for additional information on how these derivatives are used. As of December 31, 2015 and 2014 , 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: 2015 $ 2,537 $ 2,413 2014 $ 2,320 $ 2,382 The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company. |
Southern Power [Member] | |
Fair Value Disclosures [Line Items] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • Level 1 consists of observable market data in an active market for identical assets or liabilities. • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. • Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 4 $ — $ 4 Interest rate derivatives — 3 — 3 Cash equivalents 511 — — 511 Total $ 511 $ 7 $ — $ 518 Liabilities: Energy-related derivatives $ — $ 3 $ — $ 3 As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 5 $ — $ 5 Cash equivalents 18 — — 18 Total $ 18 $ 5 $ — $ 23 Liabilities: Energy-related derivatives $ — $ 4 $ — $ 4 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 9 for additional information on how these derivatives are used. As of December 31, 2015 and 2014 , 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: 2015 $ 3,122 $ 3,117 2014 $ 1,610 $ 1,785 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, 2015 | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest 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. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 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 traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity. 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 operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. • Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) 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, 2015 , the net volume of energy-related derivative contracts for natural gas positions totaled 224 million mmBtu for the Southern Company system, with the longest hedge date of 2020 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2017 for derivatives not designated as hedges. In addition to the volumes discussed above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 5 million mmBtu. For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2016 are immaterial for Southern Company. Interest Rate Derivatives Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. 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, 2015 , the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value Gain (Loss) December 31, 2015 (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 1,000 3-month LIBOR 2.37% November 2026 $ 1 1,000 3-month LIBOR 2.70% November 2046 (1 ) 200 3-month LIBOR 2.93% October 2025 (15 ) 80 3-month LIBOR 2.32% December 2026 1 Cash Flow Hedges of Existing Debt 250 3-month LIBOR + 0.32% 0.75% March 2016 — 200 3-month LIBOR + 0.40% 1.01% August 2016 — Fair Value Hedges of Existing Debt 250 1.30% 3-month LIBOR + 0.17% August 2017 1 300 2.75% 3-month LIBOR + 0.92% June 2020 2 250 5.40% 3-month LIBOR + 4.02% June 2018 1 200 4.25% 3-month LIBOR + 2.46% December 2019 2 500 1.95% 3-month LIBOR + 0.76% December 2018 (3 ) Derivatives not Designated as Hedges 65 (a,d) 3-month LIBOR 2.50% October 2016 (e) 1 47 (b,d) 3-month LIBOR 2.21% October 2016 (e) 1 65 (c,d) 3-month LIBOR 2.21% November 2016 (f) 1 Total $ 4,407 $ (8 ) ( a) Swaption at RE Tranquillity LLC. See Note 12 for additional information. ( b) Swaption at RE Roserock LLC. See Note 12 for additional information. ( c) Swaption at RE Garland Holdings LLC. See Note 12 for additional information. (d) Amortizing notional amount. (e) Represents the mandatory settlement date. Settlement amount will be based on a 15 -year amortizing swap. (f) Represents the mandatory settlement date. Settlement amount will be based on a 12 -year amortizing swap. The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2016 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2046 . Derivative Financial Statement Presentation and Amounts At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ 3 $ 7 Liabilities from risk management activities $ 130 $ 118 Other deferred charges and assets — — Other deferred credits and liabilities 87 79 Total derivatives designated as hedging instruments for regulatory purposes $ 3 $ 7 $ 217 $ 197 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets $ 3 $ — Liabilities from risk management activities $ 2 $ — Interest rate derivatives: Other current assets 19 7 Liabilities from risk management activities 23 17 Other deferred charges and assets — 1 Other deferred credits and liabilities 7 7 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 22 $ 8 $ 32 $ 24 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets $ 1 $ 6 Liabilities from risk management activities $ 1 $ 4 Interest rate derivatives: Other current assets 3 — Liabilities from risk management activities — — Total derivatives not designated as hedging instruments $ 4 $ 6 $ 1 $ 4 Total $ 29 $ 21 $ 250 $ 225 The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 7 $ 13 Energy-related derivatives presented in the Balance Sheet (a) $ 220 $ 201 Gross amounts not offset in the Balance Sheet (b) (6 ) (9 ) Gross amounts not offset in the Balance Sheet (b) (6 ) (9 ) Net energy-related derivative assets $ 1 $ 4 Net energy-related derivative liabilities $ 214 $ 192 Interest rate derivatives presented in the Balance Sheet (a) $ 22 $ 8 Interest rate derivatives presented in the Balance Sheet (a) $ 30 $ 24 Gross amounts not offset in the Balance Sheet (b) (9 ) (8 ) Gross amounts not offset in the Balance Sheet (b) (9 ) (8 ) Net interest rate derivative assets $ 13 $ — Net interest rate derivative liabilities $ 21 $ 16 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (130 ) $ (118 ) Other regulatory liabilities, current $ 3 $ 7 Other regulatory assets, deferred (87 ) (79 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (217 ) $ (197 ) $ 3 $ 7 For the years ended December 31, 2015 , 2014 , and 2013 , 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 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ (22 ) $ (16 ) $ — Interest expense, net of amounts capitalized $ (9 ) $ (8 ) $ (14 ) For the years ended December 31, 2015 , 2014 , and 2013 , the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from OCI into earnings were immaterial for Southern Company. For the years ended December 31, 2015 , 2014 , and 2013 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial and offset by changes to the carrying value of long-term debt. There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2015 , 2014 , and 2013 , the pre-tax effects of energy-related and interest rate derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company. 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, 2015 , Southern Company's collateral posted with its derivative counterparties was immaterial. At December 31, 2015 , the fair value of derivative liabilities with contingent features was $52 million . The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $52 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Alabama Power [Member] | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. 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, 2015 , the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Net Purchased mmBtu Longest Hedge Date Longest Non-Hedge Date (in millions) 50 2018 — 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, 2015 , the following interest rate derivative was outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 200 3-month 2.93% October 2025 $ (15 ) The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2016 are $4 million . The Company has deferred gains and losses that are expected to be amortized into earnings through 2035. Derivative Financial Statement Presentation and Amounts At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ 1 $ 1 Liabilities from risk management activities $ 40 $ 32 Other deferred charges and assets — — Other deferred credits and liabilities 15 21 Total derivatives designated as hedging instruments for regulatory purposes $ 1 $ 1 $ 55 $ 53 Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets $ — $ — Liabilities from risk management activities $ 15 $ 8 Total $ 1 $ 1 $ 70 $ 61 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2015 and 2014 . The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure table below. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 1 $ 1 Energy-related derivatives presented in the Balance Sheet (a) $ 55 $ 53 Gross amounts not offset in the Balance Sheet (b) (1 ) — Gross amounts not offset in the Balance Sheet (b) (1 ) — Net energy-related derivative assets $ — $ 1 Net energy-related derivative liabilities $ 54 $ 53 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. At December 31, 2015 and 2014 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (40 ) $ (32 ) Other current liabilities $ 1 $ 1 Other regulatory assets, deferred (15 ) (21 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (55 ) $ (53 ) $ 1 $ 1 For the years ended December 31, 2015 , 2014 , and 2013 , 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 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ (7 ) $ (8 ) $ — Interest expense, net of amounts capitalized $ (3 ) $ (3 ) $ (3 ) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2015 , 2014 , and 2013 , the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2015 , the Company's collateral posted with its derivative counterparties was not material. At December 31, 2015 , the fair value of derivative liabilities with contingent features was $16 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 $52 million , and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Georgia Power [Member] | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages a fuel-hedging program, implemented per the guidelines of the Georgia PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. 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, 2015 , the net volume of energy-related derivative contracts for natural gas positions totaled 50 million mmBtu, all of which expire by 2017 , which is the longest hedge date. In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 4 million mmBtu for the Company. Interest Rate Derivatives The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains and losses and the hedged items' fair value gains and losses attributable to interest rate risk are both recorded directly to earnings, providing an offset, with any differences representing ineffectiveness. At December 31, 2015 , 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 $ 250 3-month LIBOR + 0.32% 0.75% March 2016 $ — 200 3-month LIBOR + 0.40% 1.01% August 2016 — Fair Value Hedges of Existing Debt 250 5.40% 3-month LIBOR + 4.02% June 2018 1 200 4.25% 3-month LIBOR + 2.46% December 2019 2 500 1.95% 3-month LIBOR + .76% December 2018 (3 ) Total $ 1,400 $ — The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2016 are $4 million . The Company has deferred gains and losses related to interest rate derivative settlements of cash flow hedges that are expected to be amortized into earnings through 2037 . Derivative Financial Statement Presentation and Amounts At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ 2 $ 6 Liabilities from risk management activities $ 12 $ 23 Other deferred charges and assets — 1 Other deferred credits and liabilities 3 4 Total derivatives designated as hedging instruments for regulatory purposes $ 2 $ 7 $ 15 $ 27 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets $ 5 $ 5 Liabilities from risk management activities $ — $ 9 Other deferred charges and assets — 1 Other deferred credits and liabilities 6 5 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 5 $ 6 $ 6 $ 14 Total $ 7 $ 13 $ 21 $ 41 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2015 and 2014 . The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 2 $ 7 Energy-related derivatives presented in the Balance Sheet (a) $ 15 $ 27 Gross amounts not offset in the Balance Sheet (b) (2 ) (7 ) Gross amounts not offset in the Balance Sheet (b) (2 ) (7 ) Net energy-related derivative assets $ — $ — Net energy-related derivative liabilities $ 13 $ 20 Interest rate derivatives presented in the Balance Sheet (a) $ 5 $ 6 Interest rate derivatives presented in the Balance Sheet (a) $ 6 $ 14 Gross amounts not offset in the Balance Sheet (b) (4 ) (6 ) Gross amounts not offset in the Balance Sheet (b) (4 ) (6 ) Net interest rate derivative assets $ 1 $ — Net interest rate derivative liabilities $ 2 $ 8 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (12 ) $ (23 ) Other regulatory liabilities, current $ 2 $ 6 Other regulatory assets, deferred (3 ) (4 ) Other deferred credits and liabilities — 1 Total energy-related derivative gains (losses) $ (15 ) $ (27 ) $ 2 $ 7 For the years ended December 31, 2015 , 2014 , and 2013 , 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 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ (15 ) $ (8 ) $ — Interest expense, net of amounts capitalized $ (3 ) $ (3 ) $ (3 ) For the years ended December 31, 2015 and 2014 , 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 material ineffectiveness recorded in earnings for any period presented. The pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was immaterial for all years presented. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2015 , the Company's collateral posted with its derivative counterparties was immaterial. At December 31, 2015 , 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 $52 million , and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Gulf Power [Member] | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and may enter into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. 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 fuel cost recovery clause. • Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2015 , the net volume of energy-related derivative contracts for natural gas positions totaled 82 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. 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, 2015 , the following interest rate derivative was outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 80 3-month LIBOR 2.32% December 2026 $ 1 The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2016 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 At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ — $ — Liabilities from risk management activities $ 49 $ 37 Other deferred charges and assets — — Other deferred credits and liabilities 51 35 Total derivatives designated as hedging instruments for regulatory purposes $ — $ — $ 100 $ 72 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets $ 1 $ — Liabilities from risk management activities $ — $ — Total $ 1 $ — $ 100 $ 72 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2015 and 2014 . The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2015 and 2014 , energy-related derivatives and interest rate derivatives presented in the tables above do not have amounts available for offset. At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (49 ) $ (37 ) Other regulatory liabilities, current $ — $ — Other regulatory assets, deferred (51 ) (35 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (100 ) $ (72 ) $ — $ — For the years ended December 31, 2015 , 2014 , and 2013 , 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 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) (Effective Portion) Amount Derivative Category 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ 1 $ — $ — Interest expense, net of amounts capitalized $ (1 ) $ (1 ) $ (1 ) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2015 , 2014 , and 2013 , 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, 2015 , the Company's collateral posted with its derivative counterparties was not material. At December 31, 2015 , the fair value of derivative liabilities with contingent features was $22 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 $52 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Mississippi Power [Member] | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. 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, 2015 , the net volume of energy-related derivative contracts for natural gas positions totaled 32 million mmBtu for the Company, with the longest hedge date of 2018 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions. Interest Rate Derivatives The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to income. At December 31, 2015 , there were no interest rate derivatives outstanding. The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2016 are $1 million . The Company has deferred gains and losses that are expected to be amortized into earnings through 2022 . Derivative Financial Statement Presentation and Amounts At December 31, 2015 and 2014 , the fair value of energy-related derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ — $ — Other current liabilities $ 29 $ 26 Other deferred charges and assets — — Other deferred credits and liabilities 18 19 Total derivatives designated as hedging instruments for regulatory purposes $ — $ — $ 47 $ 45 Energy-related derivatives not designated as hedging instruments were immaterial for 2015 and 2014 . The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2015 and 2014 , energy-related derivatives presented in the table above did not have amounts available for offset. At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (29 ) $ (26 ) Other regulatory liabilities, current $ — $ — Other regulatory assets, deferred (18 ) (19 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (47 ) $ (45 ) $ — $ — For the years ended December 31, 2015 , 2014 , and 2013 , 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, 2015 , 2014 , and 2013 , the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were immaterial. There was no material ineffectiveness recorded in earnings for any period 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, 2015 , the Company's collateral posted with its derivative counterparties was immaterial. At December 31, 2015 , the fair value of derivative liabilities with contingent features was $12 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 $52 million , and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Southern Power [Member] | |
Derivative [Line Items] | |
DERIVATIVES | DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 8 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. 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 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, 2015 , the net volume of energy-related derivative contracts for natural gas positions totaled 10 million mmBtu, all of which expire by 2017 , which is the longest non-hedge date. At December 31, 2015 , the net volume of energy-related derivative contracts for power positions was immaterial. In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 1 million mmBtu. For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2016 is immaterial. Interest Rate Derivatives The Company may also enter into interest rate derivatives from time to time to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. 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, 2015 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Derivatives not Designated as Hedges $ 65 (a,d) 3-month LIBOR 2.50% October 2016 (e) $ 1 47 (b.d) 3-month LIBOR 2.21% October 2016 (e) 1 65 (c,d) 3-month LIBOR 2.21% November 2016 (f) 1 Total $ 177 $ 3 (a) Swaption at RE Tranquillity LLC. See Note 2 for additional information. (b) Swaption at RE Roserock LLC. See Note 2 for additional information. (c) Swaption at RE Garland Holdings LLC. See Note 2 for additional information. (d) Amortizing notional amount. (e) Represents the mandatory settlement date. Settlement amount will be based on a 15 -year amortizing swap. (f) Represents the mandatory settlement date. Settlement amount will be based on a 12 -year amortizing swap. The Company has deferred gains and losses in AOCI related to past cash flow hedges that are expected to be amortized into earnings through 2016. The estimated pre-tax loss that will be reclassified from AOCI to interest expense for the 12-month period ending December 31, 2016 is immaterial. Derivative Financial Statement Presentation and Amounts At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities $ 3 $ — Other current liabilities $ 2 $ — Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities $ 1 $ 5 Other current liabilities $ 1 $ 4 Interest rate derivatives: Assets from risk management activities 3 — Other current liabilities — — Total derivatives not designated as hedging instruments $ 4 $ 5 $ 1 $ 4 Total $ 7 $ 5 $ 3 $ 4 The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 4 $ 5 Energy-related derivatives presented in the Balance Sheet (a) $ 3 $ 4 Gross amounts not offset in the Balance Sheet (b) (1 ) — Gross amounts not offset in the Balance Sheet (b) (1 ) — Net energy-related derivative assets $ 3 $ 5 Net energy-related derivative liabilities $ 2 $ 4 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. For the years ended December 31, 2015 , 2014 , and 2013 , 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) Reclassified from AOCI into Income (Effective Portion) Amount Derivative Category Statements of Income Location 2015 2014 2013 (in millions) Interest rate derivatives Interest expense, net of amounts capitalized $ (1 ) $ (1 ) $ (6 ) For the years ended December 31, 2015 , 2014 , and 2013 , the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and reclassified from AOCI into earnings were immaterial. 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 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, 2015 , the amount of collateral posted with its derivative counterparties was immaterial. At December 31, 2015 , 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 $52 million , and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Segment and Related Information
Segment and Related Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
SEGMENT AND RELATED INFORMATION | SEGMENT AND RELATED INFORMATION The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $417 million , $383 million , and $346 million in 2015 , 2014 , and 2013 , respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2015 , 2014 , and 2013 was as follows: Electric Utilities Traditional Operating Companies Southern Power Eliminations Total All Other Eliminations Consolidated (in millions) 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 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 2014 Operating revenues $ 17,354 $ 1,501 $ (449 ) $ 18,406 $ 159 $ (98 ) $ 18,467 Depreciation and amortization 1,709 220 — 1,929 16 — 1,945 Interest income 17 1 — 18 3 (2 ) 19 Interest expense 705 89 — 794 43 (2 ) 835 Income taxes 1,056 (3 ) — 1,053 (76 ) — 977 Segment net income (loss) (a) (b) 1,797 172 — 1,969 (3 ) (3 ) 1,963 Total assets (c) 64,300 5,233 (131 ) 69,402 1,143 (312 ) 70,233 Gross property additions 5,568 942 — 6,510 11 1 6,522 2013 Operating revenues $ 16,136 $ 1,275 $ (376 ) $ 17,035 $ 139 $ (87 ) $ 17,087 Depreciation and amortization 1,711 175 — 1,886 15 — 1,901 Interest income 17 1 — 18 2 (1 ) 19 Interest expense 714 74 — 788 36 — 824 Income taxes 889 46 — 935 (85 ) (1 ) 849 Segment net income (loss) (a) (b) 1,486 166 — 1,652 (10 ) 2 1,644 Total assets (c) 59,188 4,417 (101 ) 63,504 1,064 (304 ) 64,264 Gross property additions 5,226 633 — 5,859 9 — 5,868 (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $365 million ( $226 million after tax) in 2015, $868 million ( $536 million after tax) in 2014, and $1.2 billion ( $729 million after tax) in 2013. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. (c) Net of $202 million and $139 million of unamortized debt issuance costs as of December 31, 2014 and 2013, respectively. Also net of $488 million and $143 million of deferred tax assets as of December 31, 2014 and 2013, respectively. See Note 1 under "Recently Issued Accounting Standards" for additional information. Products and Services Electric Utilities' Revenues Year Retail Wholesale Other Total (in millions) 2015 $ 14,987 $ 1,798 $ 657 $ 17,442 2014 15,550 2,184 672 18,406 2013 14,541 1,855 639 17,035 |
Noncontrolling Interest
Noncontrolling Interest | 12 Months Ended |
Dec. 31, 2015 | |
Southern Power [Member] | |
Noncontrolling Interest [Line Items] | |
NONCONTROLLING INTEREST | NONCONTROLLING INTERESTS The following table details the components of redeemable noncontrolling interests for the years ended December 31: 2015 2014 2013 (in millions) Beginning balance $ 39 $ 29 $ 8 Net income attributable to redeemable noncontrolling interests 2 4 4 Distributions to redeemable noncontrolling interests — (1 ) — Capital contributions from redeemable noncontrolling interests 2 7 17 Ending balance $ 43 $ 39 $ 29 For the years ended December 31, 2015 and 2014, net income included in the consolidated statements of changes in stockholders' equity is reconciled to net income presented in the consolidated statements of income as follows: 2015 2014 (in millions) Net income attributable to the Company $ 215 $ 172 Net income (loss) attributable to noncontrolling interests 12 (1 ) Net income attributable to redeemable noncontrolling interests 2 4 Net income $ 229 $ 175 For the year ended December 31, 2013 , net income attributable to redeemable noncontrolling interests was $4 million and was included in "Other income (expense), net" in the consolidated statements of income. |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2015 and 2014 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 2015 $ 4,183 $ 957 $ 508 $ 0.56 $ 0.56 $ 0.5250 $ 53.16 $ 43.55 June 2015 4,337 1,098 629 0.69 0.69 0.5425 45.44 41.40 September 2015 5,401 1,649 959 1.05 1.05 0.5425 46.84 41.81 December 2015 3,568 578 271 0.30 0.30 0.5425 47.50 43.38 March 2014 $ 4,644 $ 700 $ 351 $ 0.39 $ 0.39 $ 0.5075 $ 44.00 $ 40.27 June 2014 4,467 1,103 611 0.68 0.68 0.5250 46.81 42.55 September 2014 5,339 1,278 718 0.80 0.80 0.5250 45.47 41.87 December 2014 4,017 561 283 0.31 0.31 0.5250 51.28 43.55 As a result of the revisions to the cost estimate for the Kemper IGCC, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $183 million ( $113 million after tax) in the fourth quarter 2015, $150 million ( $93 million after tax) in the third quarter 2015, $23 million ( $14 million after tax) in the second quarter 2015, $9 million ( $6 million after tax) in the first quarter 2015, $70 million ( $43 million after tax) in the fourth quarter 2014, $418 million ( $258 million after tax) in the third quarter 2014, and $380 million ( $235 million after tax) in the first quarter 2014. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. The Southern Company system's business is influenced by seasonal weather conditions. |
Alabama Power [Member] | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2015 $ 1,401 $ 346 $ 169 June 2015 1,455 398 200 September 2015 1,695 555 295 December 2015 1,217 264 121 March 2014 $ 1,508 $ 381 $ 187 June 2014 1,437 357 173 September 2014 1,669 520 282 December 2014 1,328 267 119 The Company's business is influenced by seasonal weather conditions. |
Georgia Power [Member] | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2015 $ 1,978 $ 454 $ 236 June 2015 2,016 554 277 September 2015 2,691 964 551 December 2015 1,641 376 196 March 2014 $ 2,269 $ 516 $ 266 June 2014 2,186 572 311 September 2014 2,631 920 525 December 2014 1,902 288 123 The Company's business is influenced by seasonal weather conditions. |
Gulf Power [Member] | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in millions) March 2015 $ 357 $ 72 $ 37 June 2015 384 69 35 September 2015 429 91 48 December 2015 313 58 28 March 2014 $ 407 $ 74 $ 37 June 2014 384 69 34 September 2014 438 88 46 December 2014 361 50 23 The Company's business is influenced by seasonal weather conditions. |
Mississippi Power [Member] | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) After Dividends on Preferred Stock (in millions) March 2015 $ 276 $ 24 $ 35 June 2015 275 12 49 September 2015 341 (66 ) (21 ) December 2015 246 (143 ) (71 ) March 2014 $ 331 $ (325 ) $ (172 ) June 2014 311 56 62 September 2014 355 (349 ) (195 ) December 2014 246 (71 ) (24 ) As a result of the revisions to the cost estimate for the Kemper IGCC, the Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $183 million ( $113 million after tax) in the fourth quarter 2015, $150 million ( $93 million after tax) in the third quarter 2015, $23 million ( $14 million after tax) in the second quarter 2015, $9 million ( $6 million after tax) in the first quarter 2015, $70 million ( $43 million after tax) in the fourth quarter 2014, $418 million ( $258 million after tax) in the third quarter 2014, and $380 million ( $235 million after tax) in the first quarter 2014. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. The Company's business is influenced by seasonal weather conditions. |
Southern Power [Member] | |
Quarterly Financial Information [Line Items] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income Attributable to the Company (in millions) March 2015 $ 348 $ 67 $ 33 June 2015 337 75 46 September 2015 401 129 102 December 2015 304 55 34 March 2014 $ 351 $ 59 $ 33 June 2014 329 51 31 September 2014 435 105 64 December 2014 386 40 44 The Company's business is influenced by seasonal weather conditions. |
Valuation and Qualifying Accoun
Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 2014 , AND 2013 (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 2015 $ 18,253 $ 31,074 $ — $ 35,986 $ 13,341 2014 17,855 43,537 — 43,139 18,253 2013 16,984 36,788 — 35,917 17,855 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
Alabama Power [Member] | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
VALUATION AND QUALIFYING ACCOUNTS | ALABAMA POWER COMPANY SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2015 , 2014 , AND 2013 (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 2015 $ 9,143 $ 13,500 $ — $ 13,046 $ 9,597 2014 8,350 14,309 — 13,516 9,143 2013 8,450 12,327 — 12,427 8,350 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
Georgia Power [Member] | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
VALUATION AND QUALIFYING ACCOUNTS | GEORGIA POWER COMPANY SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2015 , 2014 , AND 2013 (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 2015 $ 6,076 $ 16,862 $ — $ 20,791 $ 2,147 2014 5,074 24,141 — 23,139 6,076 2013 6,259 18,362 — 19,547 5,074 ( Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
Gulf Power [Member] | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
VALUATION AND QUALIFYING ACCOUNTS | GULF POWER COMPANY SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2015 , 2014 , AND 2013 (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 2015 $ 2,087 $ 2,041 $ — $ 3,353 $ 775 2014 1,131 4,304 — 3,348 2,087 2013 1,490 1,900 — 2,259 1,131 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
Mississippi Power [Member] | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
VALUATION AND QUALIFYING ACCOUNTS | MISSISSIPPI POWER COMPANY SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2015 , 2014 , AND 2013 (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 2015 $ 825 $ (1,994 ) $ — $ (1,456 ) $ 287 2014 3,018 562 — 2,755 825 2013 373 3,757 — 1,112 3,018 ( 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 Mirror CWIP involved refunding all billed amounts to all historical customers and included an interest component. The refund of approximately $371 million was of sufficient magnitude to resolve most past due amounts beyond 30 days aged receivables, accounting for the negative provision of $(1,994) , 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 $(1,456) . For more information regarding the 2015 decision of the Mississippi Supreme Court related to the Mirror CWIP refund in fourth quarter 2015, see Note 3 to the financial statement of Mississippi Power under "Integrated Coal Gasification Combined Cycle – 2013 MPSC Rate Order" in Item 8 herein. |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Line Items] | |
General | General The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the FERC, and the traditional operating companies are also subject to regulation by their respective state PSCs. As such, each of 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 their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. In June 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, as well as the current period. 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 | Recently Issued Accounting Standards The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $202 million as of December 31, 2014. These debt issuance costs were previously presented within unamortized debt issuance expense. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 6 and 10 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million , with $488 million to non-current accumulated deferred income taxes and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of Southern Company. See Note 5 for disclosures impacted by ASU 2015-17. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The traditional operating companies are subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans $ 3,440 $ 3,469 (a,n) Deferred income tax charges 1,514 1,458 (b) Asset retirement obligations-asset 481 119 (b,n) Other regulatory assets 299 275 (k) Loss on reacquired debt 248 267 (c) Fuel-hedging-asset 225 202 (d,n) Kemper IGCC regulatory assets 216 148 (h) Vacation pay 178 177 (f,n) Deferred PPA charges 163 185 (e,n) Under recovered regulatory clause revenues 142 157 (g) Remaining net book value of retired assets 283 44 (o) Environmental remediation-asset 78 64 (j,n) Property damage reserves-asset 92 98 (i) Nuclear outage 88 99 (g) Other cost of removal obligations (1,177 ) (1,229 ) (b) Over recovered regulatory clause revenues (261 ) (48 ) (g) Deferred income tax credits (187 ) (192 ) (b) Property damage reserves-liability (178 ) (181 ) (l) Asset retirement obligations-liability (45 ) (130 ) (b,n) Other regulatory liabilities (35 ) (47 ) (m) Mirror CWIP — (271 ) (h) Total regulatory assets (liabilities), net $ 5,564 $ 4,664 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (b) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2015 , other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with Georgia Power's 2013 ARP. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years . (d) Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years . Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (e) Recovered over the life of the PPA for periods up to eight years . (f) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years . (h) For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." (i) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding six years . (j) Recovered through the environmental cost recovery clause when the remediation is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building leases, closure of Plant Scholz ash pond, Plant Daniel Units 3 and 4 regulatory assets, 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 15 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, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 15 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 not exceeding 11 years . In the event that a portion of a traditional operating company's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power," "Retail Regulatory Matters – Gulf Power, "and "Integrated Coal Gasification Combined Cycle" for additional information. |
Revenues | Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Southern Company's electric utility subsidiaries have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. |
Fuel Costs | Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. |
Income and Other Taxes | Income and Other Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional operating companies are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. 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 production tax credits (PTC), which are recorded to income tax expense based on 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 2015 and will be carried forward and utilized in future years. In addition, Southern Company has subsidiaries with various state net operating loss (NOL) carryforwards, which could result in net state income tax benefits in the future, if utilized. See Note 5 to the financial statements 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 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: 2015 2014 (in millions) Generation $ 41,648 $ 37,892 Transmission 10,544 9,884 Distribution 17,670 17,123 General 4,377 4,198 Plant acquisition adjustment 123 123 Utility plant in service 74,362 69,220 Information technology equipment and software 222 244 Communications equipment 418 439 Other 116 110 Other plant in service 756 793 Total plant in service $ 75,118 $ 70,013 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle. The refueling cycles for Alabama Power's Plant Farley and Georgia Power's Plants Hatch and Vogtle Units 1 and 2 range from 18 to 24 months , depending on the unit. Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below: Asset Balances at December 31, 2015 2014 (in millions) Office building $ 61 $ 61 Nitrogen plant 83 83 Computer-related equipment 61 60 Gas pipeline 6 6 Less: Accumulated amortization (59 ) (49 ) Balance, net of amortization $ 152 $ 161 The amount of non-cash property additions recognized for the years ended December 31, 2015 , 2014 , and 2013 was $844 million , $528 million , and $411 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, 2015 , 2014 , and 2013 was $13 million , $25 million , and $107 million , respectively. |
Depreciation, Depletion and Amortization | Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2015 , 3.1% in 2014 , and 3.3% in 2013 . Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $23.7 billion and $23.5 billion at December 31, 2015 and 2014 , respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. Cost, net of salvage value, of these assets is depreciated on an hours or starts units-of-production basis. Plant in service as of December 31, 2015 and 2014 that is depreciated on a units-of-production basis was approximately $485 million and $470 million , respectively. Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP) and the 2013 ARP, Georgia Power amortized approximately $31 million in 2013 and $14 million in each of 2014 and 2015 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under "Retail Regulatory Matters – Alabama Power – Cost of Removal Accounting Order " and "– Gulf Power – Retail Base Rate Case " for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability by Alabama Power and Gulf Power, respectively. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years . Accumulated depreciation for other plant in service totaled $510 million and $533 million at December 31, 2015 and 2014 , respectively. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations (ARO) are computed as the present value of the 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 operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 and 2 – and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17, 2015 (CCR Rule), principally ash ponds. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 2,201 $ 2,018 Liabilities incurred 662 18 Liabilities settled (37 ) (17 ) Accretion 115 102 Cash flow revisions 818 80 Balance at end of year $ 3,759 $ 2,201 The increases in liabilities incurred and cash flow revisions in 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule and Georgia Power's updated nuclear decommissioning study. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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 or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional operating companies expect to continue to periodically update these estimates. The cash flow revisions in 2014 are primarily related to Alabama Power's and SEGCO's AROs associated with asbestos at their steam generation facilities. |
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, 2015 and 2014 , approximately $76 million and $51 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 $78 million and $52 million at December 31, 2015 and 2014 , 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, 2015 , investment securities in the Funds totaled $1.5 billion , consisting of equity securities of $817 million , debt securities of $654 million , and $38 million of other securities. At December 31, 2014 , investment securities in the Funds totaled $1.5 billion , consisting of equity securities of $886 million , debt securities of $638 million , and $19 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool. Sales of the securities held in the Funds resulted in cash proceeds of $1.4 billion , $913 million , and $1.0 billion in 2015 , 2014 , and 2013 , respectively, all of which were reinvested. 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 losses on securities held in the Funds at December 31, 2015 . For 2014 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $98 million , which included $19 million related to unrealized gains and losses on securities held in the Funds at December 31, 2014 . For 2013 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million , which included $119 million related to unrealized gains on securities held in the Funds at December 31, 2013 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2015 and 2014 , the accumulated provisions for decommissioning were as follows: External Trust Funds Internal Reserves Total 2015 2014 2015 2014 2015 2014 (in millions) Plant Farley $ 734 $ 754 $ 20 $ 21 $ 754 $ 775 Plant Hatch 487 496 — — 487 496 Plant Vogtle Units 1 and 2 288 293 — — 288 293 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, 2015 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 through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction and Interest Capitalized In accordance with regulatory treatment, the traditional operating companies record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 12.8% , 16.0% , and 15.0% of net income for 2015 , 2014 , and 2013 , respectively. Cash payments for interest totaled $809 million , $732 million , and $759 million in 2015 , 2014 , and 2013 , respectively, net of amounts capitalized of $124 million , $111 million , and $92 million , respectively. |
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. |
Reserves, Damages, and Recoveries | Storm Damage Reserves Each traditional operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $40 million , $40 million , and $28 million in 2015 , 2014 , and 2013 , respectively. 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 2015 , 2014 , and 2013 , there were no such additional accruals. See Note 3 under "Retail Regulatory Matters – Alabama Power – Rate NDR" and "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively. |
Leveraged Leases | Leveraged Leases Southern Company has several leveraged lease agreements, with original terms ranging up to 45 years , which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. |
Restricted Cash and Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. |
Financial Instruments | Financial Instruments Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities 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 operating companies' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. 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 does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2015 , the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial. Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. |
Comprehensive Income | Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries. |
Alabama Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases 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. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $39 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 10 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-current accumulated deferred income taxes in the Company’s December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. |
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 $438 million , $400 million , and $340 million during 2015 , 2014 , and 2013 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $243 million , $234 million , and $211 million during 2015 , 2014 , and 2013 , respectively. The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $11 million in 2015 , $13 million in 2014 , and $13 million in 2013 . Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $8 million in 2015, $34 million in 2014, and $27 million in 2013. See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. The transmission improvements were completed in 2014. The Company received $14 million in 2015 and expects to recover approximately $12 million a year from 2016 through 2023 through a tariff with Gulf Power. 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 2015 , 2014 , or 2013 . Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Deferred income tax charges $ 522 $ 525 (a,k) Loss on reacquired debt 75 80 (b) Vacation pay 66 65 (c,j) Under/(over) recovered regulatory clause revenues (97 ) 57 (d) Fuel-hedging losses 55 53 (e,j) Other regulatory assets 53 49 (f) Asset retirement obligations (40 ) (125 ) (a) Other cost of removal obligations (722 ) (744 ) (a) Deferred income tax credits (70 ) (72 ) (a) Nuclear outage 53 56 (d) Natural disaster reserve (75 ) (84 ) (h) Other regulatory liabilities (8 ) (17 ) (e,g) Retiree benefit plans 903 882 (i,j) Remaining net book value of retired assets 76 13 (l) Total regulatory assets (liabilities), net $ 791 $ 738 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years . (c) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years . (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three 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, 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, fuel-hedging gains and nuclear fuel disposal fee. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. Nuclear fuel disposal fees are recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The balance was transferred to Rate ECR in 2015. See Note 3 for additional information. (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 $17 million for 2015 and $18 million for 2014 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 . In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. |
Revenues | Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. |
Fuel Costs | Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" for additional information. |
Income and Other Taxes | Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. 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: 2015 2014 (in millions) Generation $ 12,820 $ 11,670 Transmission 3,773 3,579 Distribution 6,432 6,196 General 1,713 1,623 Plant acquisition adjustment 12 12 Total plant in service $ 24,750 $ 23,080 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, Depletion and Amortization | Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2015 , 3.3% in 2014 and 3.2% in 2013 . 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 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. The new rates resulted in the decrease in the composite depreciation rate for 2015. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations (ARO) are computed as the present value of the 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 on April 17, 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 829 $ 730 Liabilities incurred 402 1 Liabilities settled (3 ) (3 ) Accretion 53 45 Cash flow revisions 167 56 Balance at end of year $ 1,448 $ 829 The increase in liabilities incurred and cash flow revisions in 2015 is primarily related to the Company's AROs associated with the impact of the CCR Rule on its ash and gypsum facilities. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The cash flow revisions in 2014 are primarily related to the Company's AROs associated with asbestos at its steam generation facilities. |
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, 2015 , investment securities in the Funds totaled $734 million , consisting of equity securities of $521 million , debt securities of $191 million , and $22 million of other securities. At December 31, 2014 , investment securities in the Funds totaled $754 million , consisting of equity securities of $583 million , debt securities of $163 million , and $8 million of other securities. 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 $438 million , $244 million , and $279 million in 2015 , 2014 , and 2013 , respectively, all of which were reinvested. 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 . For 2014 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $54 million , which included $19 million related to unrealized gains on securities held in the Funds at December 31, 2014 . For 2013 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million , which included $85 million related to unrealized losses on securities held in the Funds at December 31, 2013 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, the accumulated provisions for decommissioning were as follows: 2015 2014 (in millions) External trust funds $ 734 $ 754 Internal reserves 20 21 Total $ 754 $ 775 Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2015 based on the most current study performed in 2013 for Plant Farley are as follows: Decommissioning periods: Beginning year 2037 Completion year 2076 (in millions) Site study costs: Radiated structures $ 1,362 Non-radiated structures 80 Total site study costs $ 1,442 The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0% . The next site study is expected to be conducted in 2018. Amounts previously contributed to the Funds are currently projected to be adequate to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.7% in 2015 , 8.8% in 2014 , and 9.1% in 2013 . AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 9.3% in 2015 , 7.9% in 2014 , and 5.4% in 2013 . |
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. |
Restricted Cash and Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. |
Financial Instruments | Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities 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 Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. 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 does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. |
Comprehensive Income | Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. |
Variable Interest Entities | Variable Interest Entities The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets. |
Georgia Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Georgia Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases 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. 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 June 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, as well as the current period. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers , revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $124 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Notes 6 and 10 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid income taxes of $34 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. |
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 $585 million in 2015 , $555 million in 2014 , and $504 million in 2013 . Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business, operations, and construction management. Costs for these services amounted to $681 million in 2015 , $643 million in 2014 , and $555 million in 2013 . The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $179 million , $144 million , and $136 million in 2015 , 2014 , and 2013 , respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2015 and 2014 . See Note 7 under "Fuel and Purchased Power Agreements" for additional information. The Company has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $12 million in 2015 , $9 million in 2014 , and $10 million in 2013 . See Note 4 for additional information. The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015 , 2014 , or 2013 . The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans $ 1,307 $ 1,325 (a, j) Deferred income tax charges 653 668 (b, j) Loss on reacquired debt 150 163 (c, j) Asset retirement obligations 411 108 (b, j) Vacation pay 91 91 (d, j) Cancelled construction projects 56 67 (e) Remaining net book value of retired assets 171 29 (f) Storm damage reserves 92 98 (g) Other regulatory assets 140 153 (h) Other cost of removal obligations (31 ) (60 ) (b) Deferred income tax credits (105 ) (106 ) (b, j) Other regulatory liabilities (2 ) (7 ) (i, j) Total regulatory assets (liabilities), net $ 2,933 $ 2,529 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 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2015, other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with the three-year amortization period approved in the Company's 2013 ARP. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years . (d) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (e) 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. (f) Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. Amortization of obsolete inventories will be determined by the Georgia PSC in the 2016 base rate case. (g) Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding six years or through 2019. (h) Comprised of several components including deferred nuclear outages, environmental remediation, Medicare subsidy deferred income tax charges, fuel hedging losses, building lease, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding 12 years or through 2022. (i) Comprised primarily of fuel-hedging gains, which upon final settlement are refunded through the Company's fuel cost recovery mechanism. (j) Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. |
Revenues | Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. |
Fuel Costs | Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee" for additional information. |
Income and Other Taxes | Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. Federal ITCs utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. State ITCs and other credits are recognized in the period in which the credits are claimed on the state income tax return. The Company had state investment and other tax credit carryforwards totaling $318 million , which will expire between 2018 and 2026 and are expected to be fully utilized by 2022. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. |
Property, Plant, and Equipment | Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: 2015 2014 (in millions) Generation $ 15,386 $ 15,201 Transmission 5,355 5,086 Distribution 9,151 8,913 General 1,921 1,855 Plant acquisition adjustment 28 28 Total plant in service $ 31,841 $ 31,083 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively. |
Depreciation, Depletion and Amortization | Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.7% in 2015 , 2.7% in 2014 , and 3.0% in 2013 . 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 Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP) and the 2013 ARP, the Company amortized approximately $31 million in 2013 and $14 million in each of 2014 and 2015 of its remaining regulatory liability related to other cost of removal obligations. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations (ARO) are computed as the present value of the 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 of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The ARO liability 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 on April 17, 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: 2015 2014 (in millions) Balance at beginning of year $ 1,255 $ 1,222 Liabilities incurred 6 9 Liabilities settled (30 ) (12 ) Accretion 56 53 Cash flow revisions 629 (17 ) Balance at end of year $ 1,916 $ 1,255 The increase in cash flow revisions in 2015 is primarily related to changes to the Company's ash ponds, landfill, and gypsum cell ARO closure dollar and timing estimates associated with the CCR Rule and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. In preparation for the Company's next rate case, and as a part of the Company's three -year ARO update cycle, new closure estimates were developed for ash ponds, landfills, gypsum cells, nuclear decommissioning, and asbestos AROs. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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 or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The 2014 decrease in cash flow revisions is primarily related to settled AROs for asbestos remediation. |
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, 2015 and 2014 , approximately $76 million and $51 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 $78 million and $52 million at December 31, 2015 and 2014 , 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, 2015 , investment securities in the Funds totaled $775 million , consisting of equity securities of $296 million , debt securities of $463 million , and $16 million of other securities. At December 31, 2014 , investment securities in the Funds totaled $789 million , consisting of equity securities of $303 million , debt securities of $475 million , and $11 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool. Sales of the securities held in the Funds resulted in cash proceeds of $980 million , $669 million , and $705 million in 2015 , 2014 , and 2013 , respectively, all of which were reinvested. 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 losses on securities held in the Funds at December 31, 2015 . For 2014 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $44 million , which included an immaterial amount related to unrealized gains and losses on securities held in the Funds at December 31, 2014 . For 2013 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million , which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2013 . 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, 2015 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 $ 487 $ 288 For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4% . The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2015 , 2014 , and 2013 , the average AFUDC rates were 6.5% , 5.6% , and 5.3% , respectively, and AFUDC capitalized was $56 million , $62 million , and $44 million , respectively. AFUDC, net of income taxes, was 3.9% , 4.6% , and 3.3% of net income after dividends on preferred and preference stock for 2015 , 2014 , and 2013 , respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011. |
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. |
Reserves, Damages, and Recoveries | Storm Damage Recovery The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2015 and December 31, 2014 , the balance in the regulatory asset related to storm damage was $92 million and $98 million , respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62 million and $68 million included in other regulatory assets, deferred, respectively. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on the Company's earnings. Environmental Remediation Recovery The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In December 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff from 2014 through 2016. The Company recovered approximately $3 million annually through the ECCR tariff from 2011 through 2013 under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's earnings. As of December 31, 2015 , the balance of the environmental remediation liability was $29 million , with approximately $2 million included in other regulatory assets, current and approximately $30 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information. |
Restricted Cash and Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. |
Financial Instruments | Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities 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 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 statement of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. |
Comprehensive Income | Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. |
Gulf Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Gulf Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. The equity method is used for entities in which the Company has significant influence but does not control. The Company is subject to regulation by the FERC and the Florida PSC. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $8 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Note 2 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $3 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. |
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 $78 million during 2015 , 2014 , and 2013 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $12 million , $9 million , and $10 million and Mississippi Power $27 million , $31 million , and $17 million in 2015 , 2014 , and 2013 , respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. The Company has an agreement with Alabama Power under which Alabama Power has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. The transmission improvements were completed in 2014. The Company expects to pay Alabama Power approximately $12 million a year from 2016 through 2023 for these improvements. Payments by the Company to Alabama Power were $14 million , $12 million , and $8 million in 2015 , 2014 , and 2013 , respectively, for the improvements. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff. The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015 , 2014 , or 2013 . The traditional operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) PPA charges $ 163 $ 185 (j,k) Retiree benefit plans, net 147 148 (i,j) Fuel-hedging assets, net 104 73 (g,j) Deferred income tax charges 59 53 (a) Environmental remediation 46 48 (h,j) Regulatory asset, offset to other cost of removal 29 8 (m) Closure of Plant Scholz ash pond 29 — (h,j) Loss on reacquired debt 15 16 (c) Vacation pay 10 10 (d,j) Deferred return on transmission upgrades 10 — (m) Other regulatory assets, net 7 9 (l) Deferred income tax charges — Medicare subsidy 2 3 (b) Under recovered regulatory clause revenues 1 53 (e) Other cost of removal obligations (262 ) (243 ) (a) Property damage reserve (38 ) (35 ) (f) Over recovered regulatory clause revenues (22 ) — (e) Deferred income tax credits (3 ) (4 ) (a) Asset retirement obligations, net (1 ) (5 ) (a,j) Total regulatory assets (liabilities), net $ 296 $ 319 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered and amortized over periods not exceeding 14 years . (c) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years . (d) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (e) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . (f) Recorded and recovered or amortized as approved by the Florida PSC. (g) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years . Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (h) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (i) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Recovered over the life of the PPA for periods up to eight years . (l) Comprised primarily of net book value of retired meters and recovery of injuries and damages costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years . (m) Recorded as authorized by the Florida PSC in the settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. |
Revenues | Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. |
Fuel Costs | Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. |
Income and Other Taxes | Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. 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: 2015 2014 (in millions) Generation $ 2,974 $ 2,638 Transmission 691 516 Distribution 1,196 1,157 General 182 182 Plant acquisition adjustment 2 2 Total plant in service $ 5,045 $ 4,495 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. |
Depreciation, Depletion and Amortization | Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% in 2015 and 3.6% in both 2014 and 2013 . Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. As authorized by the Florida PSC in the 2013 Rate Case Settlement Agreement, the Company is 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 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional information. |
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations (ARO) are computed as the present value of the 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 on April 17, 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 in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 17 $ 16 Liabilities incurred 105 — Liabilities settled (1 ) — Accretion 2 1 Cash flow revisions 7 — Balance at end of year $ 130 $ 17 The increase in liabilities incurred in 2015 is primarily related to AROs associated with the portion of the Company's steam generation facilities impacted by the CCR Rule. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 using various assumptions related to closure in place 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, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. In connection with permitting activity related to the coal ash pond at the retired Plant Scholz facility, the Company recorded additional AROs of $29 million . |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for both 2015 and 2014 and 6.26% for 2013 . AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 10.80% , 10.93% , and 6.87% for 2015 , 2014 , and 2013 , respectively. |
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. |
Reserves, Damages, and Recoveries | Property Damage Reserve The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million , with a target level for the reserve between $48 million and $55 million . The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2015 , 2014 , and 2013 . As of December 31, 2015 and 2014 , the balance in the Company's property damage reserve totaled approximately $38 million and $35 million , respectively, which is included in deferred liabilities in the balance sheets. When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. As authorized in the 2013 Rate Case Settlement Agreement, the Company may recover costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00 / 1,000 KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional details of the 2013 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 was zero at December 31, 2015 and had a balance of $4.0 million at December 31, 2014 . Included in current liabilities and deferred credits and other liabilities in the balance sheets at December 31, 2014 is $1.6 million and $2.4 million , respectively. The Company recorded a liability with a corresponding regulatory asset of $1.7 million for estimated liabilities related to outstanding claims and suits in excess of the reserve balance at December 31, 2015 , of which $1.6 million and $0.1 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. There were no liabilities in excess of the reserve balance at December 31, 2014 . |
Restricted Cash and Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. |
Financial Instruments | Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities 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. See Note 10 for additional information regarding derivatives. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. |
Comprehensive Income | Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. |
Mississippi Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Mississippi Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. The Company is subject to regulation by the FERC and the Mississippi PSC. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers , revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $9 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 for disclosures impacted by ASU 2015-03. On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07) , effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Note 2 for disclosures impacted by ASU 2015-07. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid income taxes of $121 million with $105 million to non-current accumulated deferred income taxes and $16 million to other deferred charges in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. |
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 $295 million , $259 million , and $205 million during 2015 , 2014 , and 2013 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $11 million , $13 million , and $13 million in 2015 , 2014 , and 2013 , respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, which were $8 million , $34 million , and $27 million in 2015 , 2014 , and 2013 , respectively. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, which totaled $27 million , $31 million , and $17 million in 2015 , 2014 , and 2013 , respectively. See Note 4 for additional information. The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015 , 2014 , or 2013 . The traditional operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans – regulatory assets $ 163 $ 169 (a,g) Property damage (64 ) (62 ) (i) Deferred income tax charges 291 227 (c) Remaining net book value of retired assets 36 2 (b) Property tax 27 28 (d) Vacation pay 11 11 (e,g) Plant Daniel Units 3 and 4 regulatory assets 29 23 (j) Other regulatory assets 16 18 (b) Fuel-hedging (realized and unrealized) losses 50 47 (f,g) Asset retirement obligations 70 11 (c) Other cost of removal obligations (167 ) (166 ) (c) Kemper IGCC regulatory assets 216 148 (h) Mirror CWIP — (271 ) (h) Other regulatory liabilities (11 ) (13 ) (b) Total regulatory assets (liabilities), net $ 667 $ 172 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (b) Recorded and recovered or amortized as approved by the Mississippi PSC. (c) Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (d) Recovered through the ad valorem tax adjustment clause over a 12 -month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. (e) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. (f) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM. (g) Not earning a return as offset in rate base by a corresponding asset or liability. (h) For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." (i) For additional information, see Note 1 under "Provision for Property Damage." (j) Deferred and amortized over a 10 -year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. 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 "Integrated Coal Gasification Combined Cycle" for additional information. |
Government Grants | Government Grants In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper IGCC through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants). Through December 31, 2015 , the Company has received grant funds of $245 million , used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs. An additional $25 million is expected to be received for its initial operation. See Note 3 under "Kemper IGCC Schedule and Cost Estimate" for additional information. |
Revenues | Revenues Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually. The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.0% of the Company's total operating revenues in 2015 and are largely subject to rolling 10 -year cancellation 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 for the collection of the Company’s cost-based MRA electric tariff customers, the Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. See Note 3 under "Retail Regulatory Matters" for additional information. |
Fuel Costs | Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC. |
Income and Other Taxes | Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. 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: 2015 2014 (in millions) Generation $ 2,723 $ 2,293 Transmission 688 665 Distribution 891 854 General 503 485 Plant acquisition adjustment 81 81 Total plant in service $ 4,886 $ 4,378 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for all costs associated with operating and maintaining the Kemper IGCC assets already placed in service and a portion of the railway track maintenance costs. The portion of railway track maintenance costs not charged to operation and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. Through second quarter 2015, all costs associated with the combined cycle and the associated common facilities portion of the Kemper IGCC, excluding the lignite mine, were deferred to a regulatory asset to be recovered over the life of the Kemper IGCC. Beginning in the third quarter 2015, the Company began expensing a portion of these ongoing cost previously deferred as regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. |
Depreciation, Depletion and Amortization | Depreciation, Depletion, and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 4.7% in 2015 , 3.3% in 2014 , and 3.4% in 2013 . The increase in the 2015 depreciation rate is primarily due to an asset retirement obligation (ARO) at Plant Watson incurred as a result of changes in environmental regulations. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. On December 3, 2015, the Mississippi PSC approved the study filed in 2014, 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. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights is recognized and charged to fuel stock and is expected to be recovered through the Company’s fuel clause. Through the second quarter 2015, depreciation associated with the combined cycle and the associated common facilities portion of the Kemper IGCC was deferred as a regulatory asset to be recovered over the life of the Kemper IGCC. Beginning in the third quarter 2015, the Company began expensing certain ongoing project costs, including depreciation, that previously were deferred as regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" 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 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 on April 17, 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 the statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 48 $ 42 Liabilities incurred 101 — Liabilities settled (3 ) (3 ) Accretion 4 2 Cash flow revisions 27 7 Balance at end of year $ 177 $ 48 The increase in liabilities incurred and cash flow revisions in 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule located at Plant Watson and Plant Greene County. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2015 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, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The increase in cash flow revisions in 2014 related to the Company's AROs associated with the Plant Watson landfill and Plant Greene County asbestos. |
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 5.99% , 6.91% , and 6.89% for the years ended December 31, 2015 , 2014 , and 2013 , respectively. AFUDC equity was $110 million , $136 million , and $122 million in 2015 , 2014 , and 2013 , respectively. |
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. |
Reserves, Damages, and Recoveries | Provision for Property Damage The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. In each of 2015 , 2014 , and 2013 , the Company made retail accruals of $3 million . The Company accrued $0.3 million annually in 2015 , 2014 , and 2013 for the wholesale jurisdiction. As of December 31, 2015 , the property damage reserve balances were $63 million and $1 million for retail and wholesale, respectively. |
Restricted Cash and Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates or capitalized as part of the Kemper IGCC costs if used for testing. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the EPA are included in inventory at zero cost. |
Financial Instruments | Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities 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 qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel-hedging program as discussed below result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these would be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of operations. 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 does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. |
Comprehensive Income | Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income. |
Variable Interest Entities | Variable Interest Entities The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the construction of the Kemper IGCC. Liberty Fuels qualifies as a VIE for which the Company is the primary beneficiary. For the year ended December 31, 2015 , the VIE consolidation resulted in an ARO asset and associated liability in the amounts of $21 million and $25 million , respectively. For the year ended December 31, 2014 , the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21 million and $24 million , respectively. For the year ended December 31, 2013 , the VIE consolidation resulted in an ARO and associated liability in the amounts of $21 million and $23 million , respectively. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. |
Southern Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
General | General Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional operating companies, SCS, SouthernLINC Wireless, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Power Company and certain of its generation subsidiaries are subject to regulation by the FERC. 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 The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers (ASC 606) , revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. On February 18, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02), which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015 and is not expected to result in any additional consolidation or deconsolidation of current entities. On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03) . ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $11 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 8 for disclosures impacted by ASU 2015-03. On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $306 million and accrued income taxes of $2 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17. |
Affiliate Transactions | Affiliate Transactions 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. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS amounted to approximately $146 million in 2015 , $126 million in 2014 , and $118 million in 2013 . Of these costs, approximately $138 million in 2015 , $125 million in 2014 , and $114 million in 2013 were charged to other operations and maintenance expenses; the remainder was 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. The Company has several agreements with SCS for transmission services. Transmission purchased from affiliates totaled $11 million in 2015 , $7 million in 2014 , and $8 million in 2013 . All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $219 million , $153 million , and $150 million in 2015 , 2014 , and 2013 , respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $109 million , $75 million , and $69 million in 2015 , 2014 , and 2013 , respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. |
Acquisition Accounting | Acquisition Accounting The Company acquires generation assets as part of its overall growth strategy. For acquisitions that meet the definition of a business, the Company includes the operations in its consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition is allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business are accounted for as asset acquisitions. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions are expensed as incurred. |
Revenues | 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 operating 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. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. See "Financial Instruments" herein for additional information. Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the top three customers: 2015 2014 2013 Georgia Power 15.8 % 10.1 % 11.8 % FPL 10.7 % 9.7 % 10.7 % Duke Energy Corporation 8.2 % 9.1 % 10.3 % |
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 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 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. 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 production tax credits (PTC), which are recorded to income tax expense based on production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during the year and will be carried forward and utilized in future years. The ITC carryforwards begin expiring in 2034, but are expected to be fully utilized by 2020. See Note 5 under "Effective Tax Rate" 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 The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost. 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. |
Depreciation, Depletion and Amortization | Depreciation Beginning in 2014, the Company changed to component depreciation, where the depreciation of the original cost of assets is computed principally by the straight-line method over the estimated useful lives of assets as determined by management. Certain generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. The primary assets in property, plant, and equipment are power plants, which have estimated useful lives ranging from 30 to 45 years . The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. Plant in service as of December 31, 2015 and 2014 that is depreciated on a units-of-production basis was approximately $485 million and $470 million , respectively. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized. Prior to 2014, the Company computed depreciation of the original cost of assets under the straight-line method and applied a composite depreciation rate based on the assets' estimated useful lives as determined by management. |
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. The liability for AROs primarily relates to the Company's solar and wind facilities. Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 13 $ 4 Liabilities incurred 7 8 Accretion 1 1 Balance at end of year $ 21 $ 13 |
Long-Term Service Agreements | Long-Term Service Agreements The Company has entered into LTSAs for the purpose of securing maintenance support for substantially all of its generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in noncurrent assets on the balance sheets and are recorded as payments pursuant to LTSAs in the statements of cash flows. All work performed is capitalized or charged to expense as appropriate based on the nature of the work when performed; therefore, these charges are non-cash and are not reflected in the statements of cash flows. |
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years . The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. |
Transmission Receivables/Prepayments | Transmission Receivables/Prepayments As part of the Company's growth through the acquisition and construction of renewable facilities, the Company has transmission receivables and/or prepayments representing the reimbursable 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. |
Emission Reduction Credits | Emission Reduction Credits The Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the EPA as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost and were $11 million at each of December 31, 2015 and 2014 . The cost of emission reduction offsets to be surrendered are generally transferred to CWIP upon commencement of the related construction. |
Restricted Cash and Cash and Cash Equivalents | Restricted Cash The use of funds received under the credit facilities of RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC are restricted for construction purposes. The aggregate amount outstanding as of December 31, 2015 was $5 million and is included in other deferred charges and assets — non-affiliated. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. |
Materials and Supplies | Materials and Supplies Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. |
Fuel Inventory | Fuel Inventory Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost. |
Financial Instruments | Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. 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 does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015 . The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. |
Comprehensive Income | Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income. |
Variable Interest Entities | Variable Interest Entities The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. |
Summary of Significant Accoun30
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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: 2015 2014 Note (in millions) Retiree benefit plans $ 3,440 $ 3,469 (a,n) Deferred income tax charges 1,514 1,458 (b) Asset retirement obligations-asset 481 119 (b,n) Other regulatory assets 299 275 (k) Loss on reacquired debt 248 267 (c) Fuel-hedging-asset 225 202 (d,n) Kemper IGCC regulatory assets 216 148 (h) Vacation pay 178 177 (f,n) Deferred PPA charges 163 185 (e,n) Under recovered regulatory clause revenues 142 157 (g) Remaining net book value of retired assets 283 44 (o) Environmental remediation-asset 78 64 (j,n) Property damage reserves-asset 92 98 (i) Nuclear outage 88 99 (g) Other cost of removal obligations (1,177 ) (1,229 ) (b) Over recovered regulatory clause revenues (261 ) (48 ) (g) Deferred income tax credits (187 ) (192 ) (b) Property damage reserves-liability (178 ) (181 ) (l) Asset retirement obligations-liability (45 ) (130 ) (b,n) Other regulatory liabilities (35 ) (47 ) (m) Mirror CWIP — (271 ) (h) Total regulatory assets (liabilities), net $ 5,564 $ 4,664 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (b) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2015 , other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with Georgia Power's 2013 ARP. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years . (d) Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years . Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (e) Recovered over the life of the PPA for periods up to eight years . (f) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years . (h) For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." (i) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding six years . (j) Recovered through the environmental cost recovery clause when the remediation is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building leases, closure of Plant Scholz ash pond, Plant Daniel Units 3 and 4 regulatory assets, 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 15 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, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 15 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 not exceeding 11 years . |
Property Plant and Equipment | The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: 2015 2014 (in millions) Generation $ 41,648 $ 37,892 Transmission 10,544 9,884 Distribution 17,670 17,123 General 4,377 4,198 Plant acquisition adjustment 123 123 Utility plant in service 74,362 69,220 Information technology equipment and software 222 244 Communications equipment 418 439 Other 116 110 Other plant in service 756 793 Total plant in service $ 75,118 $ 70,013 |
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, 2015 2014 (in millions) Office building $ 61 $ 61 Nitrogen plant 83 83 Computer-related equipment 61 60 Gas pipeline 6 6 Less: Accumulated amortization (59 ) (49 ) Balance, net of amortization $ 152 $ 161 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 2,201 $ 2,018 Liabilities incurred 662 18 Liabilities settled (37 ) (17 ) Accretion 115 102 Cash flow revisions 818 80 Balance at end of year $ 3,759 $ 2,201 |
Accumulated Provisions for Decommissioning | At December 31, 2015 and 2014 , the accumulated provisions for decommissioning were as follows: External Trust Funds Internal Reserves Total 2015 2014 2015 2014 2015 2014 (in millions) Plant Farley $ 734 $ 754 $ 20 $ 21 $ 754 $ 775 Plant Hatch 487 496 — — 487 496 Plant Vogtle Units 1 and 2 288 293 — — 288 293 |
Estimated Cost of Decommissioning | The estimated costs of decommissioning as of December 31, 2015 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 |
Net Investments in Leveraged Leases | Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31: 2015 2014 (in millions) Net rentals receivable $ 1,487 $ 1,495 Unearned income (732 ) (752 ) Investment in leveraged leases 755 743 Deferred taxes from leveraged leases (303 ) (299 ) Net investment in leveraged leases $ 452 $ 444 |
Components of Income from Leveraged Leases | A summary of the components of income from the leveraged leases follows: 2015 2014 2013 (in millions) Pretax leveraged lease income (loss) $ 20 $ 24 $ (5 ) Income tax expense (7 ) (9 ) 2 Net leveraged lease income (loss) $ 13 $ 15 $ (3 ) |
Accumulated Other Comprehensive Income (Loss) Balances, Net of Tax Effects | Accumulated OCI (loss) balances, net of tax effects, were as follows: Qualifying Hedges Marketable Securities Pension and Other Postretirement Benefit Plans Accumulated Other Comprehensive Income (Loss) (in millions) Balance at December 31, 2014 $ (41 ) $ — $ (87 ) $ (128 ) Current period change (7 ) — 5 (2 ) Balance at December 31, 2015 $ (48 ) $ — $ (82 ) $ (130 ) |
Alabama Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Deferred income tax charges $ 522 $ 525 (a,k) Loss on reacquired debt 75 80 (b) Vacation pay 66 65 (c,j) Under/(over) recovered regulatory clause revenues (97 ) 57 (d) Fuel-hedging losses 55 53 (e,j) Other regulatory assets 53 49 (f) Asset retirement obligations (40 ) (125 ) (a) Other cost of removal obligations (722 ) (744 ) (a) Deferred income tax credits (70 ) (72 ) (a) Nuclear outage 53 56 (d) Natural disaster reserve (75 ) (84 ) (h) Other regulatory liabilities (8 ) (17 ) (e,g) Retiree benefit plans 903 882 (i,j) Remaining net book value of retired assets 76 13 (l) Total regulatory assets (liabilities), net $ 791 $ 738 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years . (c) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years . (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three 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, 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, fuel-hedging gains and nuclear fuel disposal fee. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. Nuclear fuel disposal fees are recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The balance was transferred to Rate ECR in 2015. See Note 3 for additional information. (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 $17 million for 2015 and $18 million for 2014 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 . |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2015 2014 (in millions) Generation $ 12,820 $ 11,670 Transmission 3,773 3,579 Distribution 6,432 6,196 General 1,713 1,623 Plant acquisition adjustment 12 12 Total plant in service $ 24,750 $ 23,080 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 829 $ 730 Liabilities incurred 402 1 Liabilities settled (3 ) (3 ) Accretion 53 45 Cash flow revisions 167 56 Balance at end of year $ 1,448 $ 829 |
Accumulated Provisions for Decommissioning | At December 31, the accumulated provisions for decommissioning were as follows: 2015 2014 (in millions) External trust funds $ 734 $ 754 Internal reserves 20 21 Total $ 754 $ 775 |
Estimated Cost of Decommissioning | The estimated costs of decommissioning as of December 31, 2015 based on the most current study performed in 2013 for Plant Farley are as follows: Decommissioning periods: Beginning year 2037 Completion year 2076 (in millions) Site study costs: Radiated structures $ 1,362 Non-radiated structures 80 Total site study costs $ 1,442 |
Gulf Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) PPA charges $ 163 $ 185 (j,k) Retiree benefit plans, net 147 148 (i,j) Fuel-hedging assets, net 104 73 (g,j) Deferred income tax charges 59 53 (a) Environmental remediation 46 48 (h,j) Regulatory asset, offset to other cost of removal 29 8 (m) Closure of Plant Scholz ash pond 29 — (h,j) Loss on reacquired debt 15 16 (c) Vacation pay 10 10 (d,j) Deferred return on transmission upgrades 10 — (m) Other regulatory assets, net 7 9 (l) Deferred income tax charges — Medicare subsidy 2 3 (b) Under recovered regulatory clause revenues 1 53 (e) Other cost of removal obligations (262 ) (243 ) (a) Property damage reserve (38 ) (35 ) (f) Over recovered regulatory clause revenues (22 ) — (e) Deferred income tax credits (3 ) (4 ) (a) Asset retirement obligations, net (1 ) (5 ) (a,j) Total regulatory assets (liabilities), net $ 296 $ 319 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered and amortized over periods not exceeding 14 years . (c) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years . (d) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (e) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . (f) Recorded and recovered or amortized as approved by the Florida PSC. (g) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years . Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (h) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (i) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Recovered over the life of the PPA for periods up to eight years . (l) Comprised primarily of net book value of retired meters and recovery of injuries and damages costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years . (m) Recorded as authorized by the Florida PSC in the settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2015 2014 (in millions) Generation $ 2,974 $ 2,638 Transmission 691 516 Distribution 1,196 1,157 General 182 182 Plant acquisition adjustment 2 2 Total plant in service $ 5,045 $ 4,495 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 17 $ 16 Liabilities incurred 105 — Liabilities settled (1 ) — Accretion 2 1 Cash flow revisions 7 — Balance at end of year $ 130 $ 17 |
Georgia Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans $ 1,307 $ 1,325 (a, j) Deferred income tax charges 653 668 (b, j) Loss on reacquired debt 150 163 (c, j) Asset retirement obligations 411 108 (b, j) Vacation pay 91 91 (d, j) Cancelled construction projects 56 67 (e) Remaining net book value of retired assets 171 29 (f) Storm damage reserves 92 98 (g) Other regulatory assets 140 153 (h) Other cost of removal obligations (31 ) (60 ) (b) Deferred income tax credits (105 ) (106 ) (b, j) Other regulatory liabilities (2 ) (7 ) (i, j) Total regulatory assets (liabilities), net $ 2,933 $ 2,529 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 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2015, other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with the three-year amortization period approved in the Company's 2013 ARP. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years . (d) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (e) 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. (f) Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. Amortization of obsolete inventories will be determined by the Georgia PSC in the 2016 base rate case. (g) Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding six years or through 2019. (h) Comprised of several components including deferred nuclear outages, environmental remediation, Medicare subsidy deferred income tax charges, fuel hedging losses, building lease, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding 12 years or through 2022. (i) Comprised primarily of fuel-hedging gains, which upon final settlement are refunded through the Company's fuel cost recovery mechanism. (j) Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2015 2014 (in millions) Generation $ 15,386 $ 15,201 Transmission 5,355 5,086 Distribution 9,151 8,913 General 1,921 1,855 Plant acquisition adjustment 28 28 Total plant in service $ 31,841 $ 31,083 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 1,255 $ 1,222 Liabilities incurred 6 9 Liabilities settled (30 ) (12 ) Accretion 56 53 Cash flow revisions 629 (17 ) Balance at end of year $ 1,916 $ 1,255 |
Accumulated Provisions for Decommissioning | The site study costs and external trust funds for decommissioning as of December 31, 2015 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 $ 487 $ 288 |
Mississippi Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2015 2014 Note (in millions) Retiree benefit plans – regulatory assets $ 163 $ 169 (a,g) Property damage (64 ) (62 ) (i) Deferred income tax charges 291 227 (c) Remaining net book value of retired assets 36 2 (b) Property tax 27 28 (d) Vacation pay 11 11 (e,g) Plant Daniel Units 3 and 4 regulatory assets 29 23 (j) Other regulatory assets 16 18 (b) Fuel-hedging (realized and unrealized) losses 50 47 (f,g) Asset retirement obligations 70 11 (c) Other cost of removal obligations (167 ) (166 ) (c) Kemper IGCC regulatory assets 216 148 (h) Mirror CWIP — (271 ) (h) Other regulatory liabilities (11 ) (13 ) (b) Total regulatory assets (liabilities), net $ 667 $ 172 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (b) Recorded and recovered or amortized as approved by the Mississippi PSC. (c) Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (d) Recovered through the ad valorem tax adjustment clause over a 12 -month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. (e) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. (f) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM. (g) Not earning a return as offset in rate base by a corresponding asset or liability. (h) For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." (i) For additional information, see Note 1 under "Provision for Property Damage." (j) Deferred and amortized over a 10 -year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. |
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: 2015 2014 (in millions) Generation $ 2,723 $ 2,293 Transmission 688 665 Distribution 891 854 General 503 485 Plant acquisition adjustment 81 81 Total plant in service $ 4,886 $ 4,378 |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 48 $ 42 Liabilities incurred 101 — Liabilities settled (3 ) (3 ) Accretion 4 2 Cash flow revisions 27 7 Balance at end of year $ 177 $ 48 |
Southern Power [Member] | |
Summary of Significant Accounting Policies [Line Items] | |
Schedule of Revenue by Major Customers by Reporting Segments | The following table shows the percentage of total revenues for the top three customers: 2015 2014 2013 Georgia Power 15.8 % 10.1 % 11.8 % FPL 10.7 % 9.7 % 10.7 % Duke Energy Corporation 8.2 % 9.1 % 10.3 % |
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: 2015 2014 (in millions) Balance at beginning of year $ 13 $ 4 Liabilities incurred 7 8 Accretion 1 1 Balance at end of year $ 21 $ 13 |
Future Amortization Expense for PPAs | The amortization expense for the acquired PPAs for each of the years ended December 31, 2015 , 2014 , and 2013 was $3 million , and is recorded in operating revenues. The amortization expense for future periods is as follows: Amortization Expense (in millions) 2016 $ 10 2017 17 2018 17 2019 17 2020 17 2021 and beyond 239 Total $ 317 |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.17 % 5.02 % 4.26 % Discount rate – service costs 4.48 5.02 4.26 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.04 % 4.85 % 4.05 % Discount rate – service costs 4.39 4.85 4.05 Expected long-term return on plan assets 6.97 7.15 7.13 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.67 % 4.17 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.51 % 4.04 % Annual salary increase 4.46 3.59 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 |
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, 2015 as follows: 1 Percent 1 Percent (in millions) Benefit obligation $ 119 $ (102 ) Service and interest costs 4 (4 ) |
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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 10,909 $ 8,863 Service cost 257 213 Interest cost 445 435 Benefits paid (487 ) (382 ) Actuarial loss (gain) (582 ) 1,780 Balance at end of year 10,542 10,909 Change in plan assets Fair value of plan assets at beginning of year 9,690 8,733 Actual return (loss) on plan assets (14 ) 797 Employer contributions 45 542 Benefits paid (487 ) (382 ) Fair value of plan assets at end of year 9,234 9,690 Accrued liability $ (1,308 ) $ (1,219 ) |
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, 2015 and 2014 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 2016 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2015: Accumulated OCI $ 3 $ 122 Regulatory assets 27 2,971 Total $ 30 $ 3,093 Balance at December 31, 2014: Accumulated OCI $ 4 $ 130 Regulatory assets 51 3,022 Total $ 55 $ 3,152 Estimated amortization in net periodic pension cost in 2016: Accumulated OCI $ 1 $ 6 Regulatory assets 13 145 Total $ 14 $ 151 |
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, 2015 and 2014 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2013 $ 64 $ 1,651 Net gain 75 1,552 Change in prior service costs — 1 Reclassification adjustments: Amortization of prior service costs (1 ) (25 ) Amortization of net gain (4 ) (106 ) Total reclassification adjustments (5 ) (131 ) Total change 70 1,422 Balance at December 31, 2014 $ 134 $ 3,073 Net loss 1 155 Reclassification adjustments: Amortization of prior service costs (1 ) (24 ) Amortization of net gain (9 ) (206 ) Total reclassification adjustments (10 ) (230 ) Total change (9 ) (75 ) Balance at December 31, 2015 $ 125 $ 2,998 |
Estimated pension benefit payments | At December 31, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 450 2017 478 2018 501 2019 527 2020 554 2021 to 2025 3,141 |
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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 1,986 $ 1,682 Service cost 23 21 Interest cost 78 79 Benefits paid (102 ) (102 ) Actuarial loss (gain) (38 ) 300 Plan amendments 34 (2 ) Retiree drug subsidy 8 8 Balance at end of year 1,989 1,986 Change in plan assets Fair value of plan assets at beginning of year 900 901 Actual return (loss) on plan assets (12 ) 54 Employer contributions 39 39 Benefits paid (94 ) (94 ) Fair value of plan assets at end of year 833 900 Accrued liability $ (1,156 ) $ (1,086 ) |
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, 2015 and 2014 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 2016 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2015: Accumulated OCI $ — $ 8 Net regulatory assets 32 379 Total $ 32 $ 387 Balance at December 31, 2014: Accumulated OCI $ — $ 8 Net regulatory assets 2 364 Total $ 2 $ 372 Estimated amortization as net periodic postretirement benefit cost in 2016: Net regulatory assets $ 6 $ 14 |
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2013 $ 1 $ 73 Net gain 7 301 Change in prior service costs — (2 ) Reclassification adjustments: Amortization of prior service costs — (4 ) Amortization of net gain — (2 ) Total reclassification adjustments — (6 ) Total change 7 293 Balance at December 31, 2014 $ 8 $ 366 Net gain — 33 Change in prior service costs — 33 Reclassification adjustments: Amortization of prior service costs — (4 ) Amortization of net gain — (17 ) Total reclassification adjustments — (21 ) Total change — 45 Balance at December 31, 2015 $ 8 $ 411 |
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) 2016 $ 123 $ (9 ) $ 114 2017 128 (10 ) 118 2018 133 (11 ) 122 2019 137 (12 ) 125 2020 139 (12 ) 127 2021 to 2025 711 (65 ) 646 |
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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 42 % 38 % 41 % International equity 21 23 23 Domestic fixed income 24 26 26 Global fixed income 4 4 3 Special situations 1 1 — Real estate investments 5 6 5 Private equity 3 2 2 Total 100 % 100 % 100 % |
Pension Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 2,998 $ 3,073 Other current liabilities (46 ) (42 ) Employee benefit obligations (1,262 ) (1,177 ) Accumulated OCI 125 134 |
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 257 $ 213 $ 232 Interest cost 445 435 389 Expected return on plan assets (724 ) (645 ) (603 ) Recognized net loss 215 110 200 Net amortization 25 26 27 Net periodic pension cost $ 218 $ 139 $ 245 |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 1,632 $ 681 $ — $ — $ 2,313 International equity* 1,190 990 — — 2,180 Fixed income: U.S. Treasury, government, and agency bonds — 454 — — 454 Mortgage- and asset-backed securities — 199 — — 199 Corporate bonds — 1,140 — — 1,140 Pooled funds — 500 — — 500 Cash equivalents and other — 145 — — 145 Real estate investments 299 — — 1,218 1,517 Private equity — — — 635 635 Total $ 3,121 $ 4,109 $ — $ 1,853 $ 9,083 Liabilities: Derivatives $ (1 ) $ — $ — $ — $ (1 ) Total $ 3,120 $ 4,109 $ — $ 1,853 $ 9,082 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 1,704 $ 704 $ — $ — $ 2,408 International equity* 1,070 986 — — 2,056 Fixed income: U.S. Treasury, government, and agency bonds — 699 — — 699 Mortgage- and asset-backed securities — 188 — — 188 Corporate bonds — 1,135 — — 1,135 Pooled funds — 514 — — 514 Cash equivalents and other 3 660 — — 663 Real estate investments 293 — — 1,121 1,414 Private equity — — — 570 570 Total $ 3,070 $ 4,886 $ — $ 1,691 $ 9,647 Liabilities: Derivatives $ (2 ) $ — $ — $ — $ (2 ) Total $ 3,068 $ 4,886 $ — $ 1,691 $ 9,645 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 433 $ 387 Other current liabilities (4 ) (4 ) Employee benefit obligations (1,152 ) (1,082 ) Other regulatory liabilities, deferred (22 ) (21 ) Accumulated OCI 8 8 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 23 $ 21 $ 24 Interest cost 78 79 74 Expected return on plan assets (58 ) (59 ) (56 ) Net amortization 21 6 21 Net periodic postretirement benefit cost $ 64 $ 47 $ 63 |
Fair values of benefit plan assets | Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Total As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity* $ 106 $ 52 $ — $ — $ 158 International equity* 40 64 — — 104 Fixed income: U.S. Treasury, government, and agency bonds — 22 — — 22 Mortgage- and asset-backed securities — 7 — — 7 Corporate bonds — 38 — — 38 Pooled funds — 42 — — 42 Cash equivalents and other 11 9 — — 20 Trust-owned life insurance — 370 — — 370 Real estate investments 11 — — 41 52 Private equity — — — 21 21 Total $ 168 $ 604 $ — $ 62 $ 834 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 147 $ 56 $ — $ — $ 203 International equity* 36 67 — — 103 Fixed income: U.S. Treasury, government, and agency bonds — 29 — — 29 Mortgage- and asset-backed securities — 6 — — 6 Corporate bonds — 39 — — 39 Pooled funds — 41 — — 41 Cash equivalents and other 9 27 — — 36 Trust-owned life insurance — 381 — — 381 Real estate investments 11 — — 37 48 Private equity — — — 19 19 Total $ 203 $ 646 $ — $ 56 $ 905 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Alabama Power [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.18 % 5.02 % 4.27 % Discount rate – service costs 4.49 5.02 4.27 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.04 % 4.86 % 4.06 % Discount rate – service costs 4.40 4.86 4.06 Expected long-term return on plan assets 7.17 7.34 7.36 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.67 % 4.18 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.51 % 4.04 % Annual salary increase 4.46 3.59 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 |
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, 2015 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 29 $ (25 ) 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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,592 $ 2,112 Service cost 59 48 Interest cost 106 103 Benefits paid (120 ) (100 ) Actuarial loss (gain) (131 ) 429 Balance at end of year 2,506 2,592 Change in plan assets Fair value of plan assets at beginning of year 2,396 2,278 Actual return (loss) on plan assets (9 ) 207 Employer contributions 12 11 Benefits paid (120 ) (100 ) Fair value of plan assets at end of year 2,279 2,396 Accrued liability $ (227 ) $ (196 ) |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 95 $ 68 Other regulatory liabilities, deferred (13 ) (14 ) Employee benefit obligations (142 ) (111 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 822 $ 827 Other current liabilities (11 ) (10 ) Employee benefit obligations (216 ) (186 ) |
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, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 19 $ 15 $ 4 Net (gain) loss 63 39 2 Net regulatory assets $ 82 $ 54 Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 6 $ 12 $ 3 Net (gain) loss 816 815 40 Regulatory assets $ 822 $ 827 |
Components of other comprehensive income along with changes in balances of regulatory assets and regulatory liabilities related to defined benefit pension plans | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Net regulatory assets (liabilities): Beginning balance $ 54 $ (15 ) Net (gain) loss 25 73 Change in prior service costs 8 — Reclassification adjustments: Amortization of prior service costs (3 ) (4 ) Amortization of net gain (loss) (2 ) — Total reclassification adjustments (5 ) (4 ) Total change 28 69 Ending balance $ 82 $ 54 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 827 $ 476 Net (gain) loss 56 389 Reclassification adjustments: Amortization of prior service costs (6 ) (7 ) Amortization of net gain (loss) (55 ) (31 ) Total reclassification adjustments (61 ) (38 ) Total change (5 ) 351 Ending balance $ 822 $ 827 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 6 $ 5 $ 6 Interest cost 20 20 19 Expected return on plan assets (26 ) (25 ) (23 ) Net amortization 5 4 5 Net periodic postretirement benefit cost $ 5 $ 4 $ 7 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 59 $ 48 $ 52 Interest cost 106 103 93 Expected return on plan assets (178 ) (168 ) (157 ) Recognized net loss 55 31 52 Net amortization 6 7 7 Net periodic pension cost $ 48 $ 21 $ 47 |
Estimated pension benefit payments | Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: Benefit Payments Subsidy Receipts Total (in millions) 2016 $ 33 $ (3 ) $ 30 2017 34 (3 ) 31 2018 34 (3 ) 31 2019 35 (4 ) 31 2020 36 (4 ) 32 2021 to 2025 184 (20 ) 164 At December 31, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 114 2017 119 2018 124 2019 129 2020 134 2021 to 2025 740 |
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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 503 $ 431 Service cost 6 5 Interest cost 20 20 Benefits paid (27 ) (27 ) Actuarial loss (gain) (7 ) 71 Plan amendment 7 — Retiree drug subsidy 3 3 Balance at end of year 505 503 Change in plan assets Fair value of plan assets at beginning of year 392 389 Actual return (loss) on plan assets (6 ) 23 Employer contributions 1 4 Benefits paid (24 ) (24 ) Fair value of plan assets at end of year 363 392 Accrued liability $ (142 ) $ (111 ) |
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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 48 % 45 % 48 % International equity 20 20 20 Domestic fixed income 24 27 26 Special situations 1 1 — Real estate investments 4 5 4 Private equity 3 2 2 Total 100 % 100 % 100 % |
Fair values of benefit plan assets | Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 57 $ 8 $ — $ — $ 65 International equity* 14 12 — — 26 Fixed income: U.S. Treasury, government, and agency bonds — 8 — — 8 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 13 — — 13 Pooled funds — 6 — — 6 Cash equivalents and other 1 2 — — 3 Trust-owned life insurance — 212 — — 212 Real estate investments 5 — — 14 19 Private equity — — — 7 7 Total $ 77 $ 263 $ — $ 21 $ 361 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 76 $ 8 $ — $ — $ 84 International equity* 13 12 — — 25 Fixed income: U.S. Treasury, government, and agency bonds — 10 — — 10 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 14 — — 14 Pooled funds — 6 — — 6 Cash equivalents and other — 8 — — 8 Trust-owned life insurance — 217 — — 217 Real estate investments 5 — — 13 18 Private equity — — — 7 7 Total $ 94 $ 277 $ — $ 20 $ 391 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 403 $ 168 $ — $ — $ 571 International equity* 294 244 — — 538 Fixed income: U.S. Treasury, government, and agency bonds — 112 — — 112 Mortgage- and asset-backed securities — 49 — — 49 Corporate bonds — 280 — — 280 Pooled funds — 123 — — 123 Cash equivalents and other — 36 — — 36 Real estate investments 74 — — 301 375 Private equity — — — 157 157 Total $ 771 $ 1,012 $ — $ 458 $ 2,241 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 421 $ 174 $ — $ — $ 595 International equity* 264 244 — — 508 Fixed income: U.S. Treasury, government, and agency bonds — 173 — — 173 Mortgage- and asset-backed securities — 47 — — 47 Corporate bonds — 280 — — 280 Pooled funds — 127 — — 127 Cash equivalents and other 1 163 — — 164 Real estate investments 73 — — 277 350 Private equity — — — 141 141 Total $ 759 $ 1,208 $ — $ 418 $ 2,385 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Georgia Power [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | 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: 2015 2014 2013 Pension plans Discount rates – interest costs 4.18 % 5.02 % 4.27 % Discount rates – service costs 4.49 5.02 4.27 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.03 % 4.85 % 4.04 % Discount rate – service costs 4.39 4.85 4.04 Expected long-term return on plan assets 6.48 6.75 6.74 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.65 % 4.18 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.49 % 4.03 % Annual salary increase 4.46 3.59 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 |
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, 2015 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 58 $ (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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 3,781 $ 3,116 Service cost 73 62 Interest cost 154 153 Benefits paid (188 ) (149 ) Actuarial loss (gain) (205 ) 599 Balance at end of year 3,615 3,781 Change in plan assets Fair value of plan assets at beginning of year 3,383 3,085 Actual return (loss) on plan assets (13 ) 285 Employer contributions 14 162 Benefits paid (188 ) (149 ) Fair value of plan assets at end of year 3,196 3,383 Accrued liability $ (419 ) $ (398 ) |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 223 $ 213 Employee benefit obligations (496 ) (469 ) Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 1,076 $ 1,102 Current liabilities, other (13 ) (12 ) Employee benefit obligations (406 ) (386 ) |
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, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 8 $ 17 $ 5 Net (gain) loss 1,068 1,085 55 Regulatory assets $ 1,076 $ 1,102 Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 8 $ (5 ) $ 1 Net (gain) loss 215 218 9 Regulatory assets $ 223 $ 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, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 1,102 $ 610 Net (gain) loss 59 543 Reclassification adjustments: Amortization of prior service costs (9 ) (10 ) Amortization of net gain (loss) (76 ) (41 ) Total reclassification adjustments (85 ) (51 ) Total change (26 ) 492 Ending balance $ 1,076 $ 1,102 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 7 $ 6 $ 7 Interest cost 34 34 31 Expected return on plan assets (24 ) (25 ) (24 ) Net amortization 11 2 12 Net periodic postretirement benefit cost $ 28 $ 17 $ 26 Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 73 $ 62 $ 69 Interest cost 154 153 138 Expected return on plan assets (251 ) (228 ) (212 ) Recognized net loss 76 41 74 Net amortization 9 10 10 Net periodic pension cost $ 61 $ 38 $ 79 |
Estimated pension benefit payments | At December 31, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 168 2017 176 2018 183 2019 189 2020 197 2021 to 2025 1,085 |
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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 864 $ 723 Service cost 7 6 Interest cost 34 34 Benefits paid (45 ) (44 ) Actuarial loss (gain) (22 ) 142 Plan amendment 12 — Retiree drug subsidy 4 3 Balance at end of year 854 864 Change in plan assets Fair value of plan assets at beginning of year 395 407 Actual return (loss) on plan assets (6 ) 21 Employer contributions 10 8 Benefits paid (41 ) (41 ) Fair value of plan assets at end of year 358 395 Accrued liability $ (496 ) $ (469 ) |
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 213 $ 69 Net (gain) loss 9 146 Change in prior service costs 12 — Reclassification adjustments: Amortization of net gain (loss) (11 ) (2 ) Total change 10 144 Ending balance $ 223 $ 213 |
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) 2016 $ 53 $ (4 ) $ 49 2017 55 (4 ) 51 2018 58 (5 ) 53 2019 59 (5 ) 54 2020 60 (5 ) 55 2021 to 2025 305 (28 ) 277 |
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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 40 % 34 % 38 % International equity 21 27 26 Domestic fixed income 23 25 24 Global fixed income 9 8 7 Special situations 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 other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 30 $ 36 $ — $ — $ 66 International equity* 12 41 — — 53 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 12 — — 12 Pooled funds — 30 — — 30 Cash equivalents and other 10 6 — — 16 Trust-owned life insurance — 158 — — 158 Real estate investments 3 — — 12 15 Private equity — — — 7 7 Total $ 55 $ 290 $ — $ 19 $ 364 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 53 $ 40 $ — $ — $ 93 International equity* 11 45 — — 56 Fixed income: U.S. Treasury, government, and agency bonds — 7 — — 7 Mortgage- and asset-backed securities — 2 — — 2 Corporate bonds — 12 — — 12 Pooled funds — 29 — — 29 Cash equivalents and other 8 11 — — 19 Trust-owned life insurance — 162 — — 162 Real estate investments 3 — — 12 15 Private equity — — — 6 6 Total $ 75 $ 308 $ — $ 18 $ 401 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 565 $ 236 $ — $ — $ 801 International equity* 412 343 — — 755 Fixed income: U.S. Treasury, government, and agency bonds — 157 — — 157 Mortgage- and asset-backed securities — 69 — — 69 Corporate bonds — 394 — — 394 Pooled funds — 173 — — 173 Cash equivalents and other — 50 — — 50 Real estate investments 103 — — 421 524 Private equity — — — 220 220 Total $ 1,080 $ 1,422 $ — $ 641 $ 3,143 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 595 $ 246 $ — $ — $ 841 International equity* 373 344 — — 717 Fixed income: U.S. Treasury, government, and agency bonds — 244 — — 244 Mortgage- and asset-backed securities — 66 — — 66 Corporate bonds — 398 — — 398 Pooled funds — 179 — — 179 Cash equivalents and other 1 230 — — 231 Real estate investments 102 — — 391 493 Private equity — — — 199 199 Total $ 1,071 $ 1,707 $ — $ 590 $ 3,368 Liabilities: Derivatives $ (1 ) $ — $ — $ — $ (1 ) Total $ 1,070 $ 1,707 $ — $ 590 $ 3,367 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Gulf Power [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | The weighted average rates assumed in the actuarial calculations used to determine both the 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.18 % 5.02 % 4.27 % Discount rate – service costs 4.48 5.02 4.27 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.04 % 4.86 % 4.06 % Discount rate – service costs 4.38 4.86 4.06 Expected long-term return on plan assets 8.07 8.08 8.04 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.71 % 4.18 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.51 % 4.04 % Annual salary increase 4.46 3.59 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 |
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, 2015 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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 491 $ 395 Service cost 12 10 Interest cost 20 19 Benefits paid (20 ) (16 ) Actuarial loss (gain) (23 ) 83 Balance at end of year 480 491 Change in plan assets Fair value of plan assets at beginning of year 435 386 Actual return on plan assets 4 34 Employer contributions 1 31 Benefits paid (20 ) (16 ) Fair value of plan assets at end of year 420 435 Accrued liability $ (60 ) $ (56 ) |
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, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 2 $ 3 $ 1 Net loss 140 143 6 Regulatory assets $ 142 $ 146 |
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, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 146 $ 75 Net (gain) loss 6 77 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (9 ) (5 ) Total reclassification adjustments (10 ) (6 ) Total change (4 ) 71 Ending balance $ 142 $ 146 |
Estimated pension benefit payments | At December 31, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 19 2017 20 2018 21 2019 22 2020 24 2021 to 2025 139 |
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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 78 $ 69 Service cost 1 1 Interest cost 3 3 Benefits paid (4 ) (4 ) Actuarial loss (gain) (1 ) 11 Plan amendment 4 (2 ) Retiree drug subsidy — — Balance at end of year 81 78 Change in plan assets Fair value of plan assets at beginning of year 18 17 Actual return on plan assets — 2 Employer contributions 3 3 Benefits paid (4 ) (4 ) Fair value of plan assets at end of year 17 18 Accrued liability $ (64 ) $ (60 ) |
Amounts included in accumulated other comprehensive income and regulatory assets related to other postretirement benefit plans | Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ — $ (2 ) $ — Net loss 5 4 — Net regulatory assets (liabilities) $ 5 $ 2 |
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Net regulatory assets (liabilities): Beginning balance $ 2 $ (7 ) Net (gain) loss 1 11 Change in prior service costs 2 (2 ) Reclassification adjustments: Amortization of prior service costs — — Amortization of net gain (loss) — — Total reclassification adjustments — — Total change 3 9 Ending balance $ 5 $ 2 |
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) 2016 $ 5 $ — $ 5 2017 5 — 5 2018 6 — 6 2019 6 (1 ) 5 2020 6 (1 ) 5 2021 to 2025 29 (3 ) 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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 25 % 29 % 29 % International equity 24 22 22 Domestic fixed income 25 25 29 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % |
Gulf Power [Member] | Pension Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 142 $ 146 Current liabilities, other (1 ) (1 ) Employee benefit obligations (59 ) (55 ) |
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 12 $ 10 $ 11 Interest cost 20 19 17 Expected return on plan assets (32 ) (28 ) (26 ) Recognized net loss 9 5 9 Net amortization 1 1 1 Net periodic pension cost $ 10 $ 7 $ 12 |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 73 $ 31 $ — $ — $ 104 International equity* 54 45 — — 99 Fixed income: U.S. Treasury, government, and agency bonds — 21 — — 21 Mortgage- and asset-backed securities — 9 — — 9 Corporate bonds — 51 — — 51 Pooled funds — 23 — — 23 Cash equivalents and other — 7 — — 7 Real estate investments 14 — — 55 69 Private equity — — — 29 29 Total $ 141 $ 187 $ — $ 84 $ 412 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 77 $ 32 $ — $ — $ 109 International equity* 48 44 — — 92 Fixed income: U.S. Treasury, government, and agency bonds — 31 — — 31 Mortgage- and asset-backed securities — 8 — — 8 Corporate bonds — 51 — — 51 Pooled funds — 23 — — 23 Cash equivalents and other — 30 — — 30 Real estate investments 13 — — 50 63 Private equity — — — 26 26 Total $ 138 $ 219 $ — $ 76 $ 433 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 10 $ 6 Current liabilities, other (1 ) (1 ) Other regulatory liabilities, deferred (5 ) (4 ) Employee benefit obligations (63 ) (59 ) |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (1 ) (1 ) (1 ) Net amortization — — — 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, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 3 $ 1 $ — $ — $ 4 International equity* 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Mortgage- and asset-backed securities — — — — — 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 $ 7 $ 7 $ — $ 3 $ 17 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 3 $ 1 $ — $ — $ 4 International equity* 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Mortgage- and asset-backed securities — 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 $ 6 $ 9 $ — $ 3 $ 18 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Mississippi Power [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | The weighted average rates assumed in the actuarial calculations used to determine both the 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: 2015 2014 2013 Pension plans Discount rate – interest costs 4.17 % 5.01 % 4.26 % Discount rate – service costs 4.49 5.01 4.26 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 3.59 3.59 3.59 Other postretirement benefit plans Discount rate – interest costs 4.03 % 4.85 % 4.04 % Discount rate – service costs 4.38 4.85 4.04 Expected long-term return on plan assets 7.23 7.30 7.04 Annual salary increase 3.59 3.59 3.59 Assumptions used to determine benefit obligations: 2015 2014 Pension plans Discount rate 4.69 % 4.17 % Annual salary increase 4.46 3.59 Other postretirement benefit plans Discount rate 4.47 % 4.03 % Annual salary increase 4.46 3.59 |
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2015 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2024 Post-65 medical 5.50 4.50 2024 Post-65 prescription 10.00 4.50 2025 |
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, 2015 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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 513 $ 409 Service cost 13 10 Interest cost 21 20 Benefits paid (22 ) (17 ) Actuarial loss (gain) (25 ) 91 Balance at end of year 500 513 Change in plan assets Fair value of plan assets at beginning of year 446 387 Actual return on plan assets 4 40 Employer contributions 2 36 Benefits paid (22 ) (17 ) Fair value of plan assets at end of year 430 446 Accrued liability $ (70 ) $ (67 ) |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 21 $ 18 Other regulatory liabilities, deferred (3 ) (2 ) Employee benefit obligations (74 ) (72 ) |
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, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Regulatory assets: Beginning balance $ 151 $ 78 Net (gain) loss 4 79 Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (10 ) (5 ) Total reclassification adjustments (11 ) (6 ) Total change (7 ) 73 Ending balance $ 144 $ 151 |
Estimated pension benefit payments | At December 31, 2015 , estimated benefit payments were as follows: Benefit Payments (in millions) 2016 $ 20 2017 21 2018 22 2019 24 2020 25 2021 to 2025 146 |
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, 2015 and 2014 were as follows: 2015 2014 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 96 $ 81 Service cost 1 1 Interest cost 4 4 Benefits paid (5 ) (5 ) Actuarial loss (gain) (1 ) 14 Plan amendment 1 — Retiree drug subsidy 1 1 Balance at end of year 97 96 Change in plan assets Fair value of plan assets at beginning of year 24 23 Actual return on plan assets — 2 Employer contributions 3 3 Benefits paid (4 ) (4 ) Fair value of plan assets at end of year 23 24 Accrued liability $ (74 ) $ (72 ) |
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table: 2015 2014 (in millions) Net regulatory assets (liabilities): Beginning balance $ 16 $ 2 Net (gain) loss — 14 Change in prior service costs 3 — Reclassification adjustments: Amortization of net gain (loss) (1 ) — Total reclassification adjustments (1 ) — Total change 2 14 Ending balance $ 18 $ 16 |
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) 2016 $ 6 $ — $ 6 2017 6 (1 ) 5 2018 6 (1 ) 5 2019 7 (1 ) 6 2020 7 (1 ) 6 2021 to 2025 36 (2 ) 34 |
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, 2015 and 2014 , along with the targeted mix of assets for each plan, is presented below: Target 2015 2014 Pension plan assets: Domestic equity 26 % 30 % 30 % International equity 25 23 23 Fixed income 23 23 27 Special situations 3 2 1 Real estate investments 14 16 14 Private equity 9 6 5 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 21 % 24 % 24 % International equity 20 18 19 Domestic fixed income 38 38 41 Special situations 3 2 1 Real estate investments 11 13 11 Private equity 7 5 4 Total 100 % 100 % 100 % |
Mississippi Power [Member] | Pension Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following: 2015 2014 (in millions) Other regulatory assets, deferred $ 144 $ 151 Other current liabilities (3 ) (2 ) Employee benefit obligations (67 ) (65 ) |
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, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ 2 $ 3 $ 1 Net loss 142 148 7 Regulatory assets $ 144 $ 151 |
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: 2015 2014 2013 (in millions) Service cost $ 13 $ 10 $ 11 Interest cost 21 20 18 Expected return on plan assets (33 ) (29 ) (27 ) Recognized net loss 10 5 10 Net amortization 1 1 1 Net periodic pension cost $ 12 $ 7 $ 13 |
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 76 $ 32 $ — $ — $ 108 International equity* 55 46 — — 101 Fixed income: U.S. Treasury, government, and agency bonds — 21 — — 21 Mortgage- and asset-backed securities — 9 — — 9 Corporate bonds — 53 — — 53 Pooled funds — 23 — — 23 Cash equivalents and other — 7 — — 7 Real estate investments 14 — — 57 71 Private equity — — — 30 30 Total $ 145 $ 191 $ — $ 87 $ 423 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 78 $ 32 $ — $ — $ 110 International equity* 49 45 — — 94 Fixed income: U.S. Treasury, government, and agency bonds — 32 — — 32 Mortgage- and asset-backed securities — 9 — — 9 Corporate bonds — 53 — — 53 Pooled funds — 24 — — 24 Cash equivalents and other — 30 — — 30 Real estate investments 14 — — 51 65 Private equity — — — 26 26 Total $ 141 $ 225 $ — $ 77 $ 443 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2015 and 2014 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 2016 . 2015 2014 Estimated Amortization in 2016 (in millions) Prior service cost $ — $ (2 ) $ — Net (gain) loss (18 ) 18 1 Net regulatory assets $ (18 ) $ 16 |
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: 2015 2014 2013 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 4 4 4 Expected return on plan assets (2 ) (2 ) (1 ) Net amortization 1 — — Net periodic postretirement benefit cost $ 4 $ 3 $ 4 |
Fair values of benefit plan assets | The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity* $ 3 $ 1 $ — $ — $ 4 International equity* 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 6 — — 6 Mortgage- and asset-backed securities — — — — — Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 — — — 1 Real estate investments 1 — — 3 4 Private equity — — — 1 1 Total $ 7 $ 12 $ — $ 4 $ 23 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2014: (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 — 6 — — 6 Mortgage- and asset-backed securities — — — — — Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 1 1 — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 7 $ 14 $ — $ 3 $ 24 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition [Line Items] | |
Schedule of Construction Projects | Solar Facility Seller Approx. Nameplate Capacity County Location in Georgia Expected/Actual COD PPA Counterparties PPA Contract Period Estimated Construction Cost (MW) (in millions) Sandhills N/A 146 Taylor Fourth quarter 2016 Cobb, Flint, and Sawnee Electric Membership Corporations 25 years $ 260 - 280 Decatur Parkway TradeWind Energy, Inc. 84 Decatur December 31, 2015 Georgia Power (a) 25 years Approx. $169 (c) Decatur County TradeWind Energy, Inc. 20 Decatur December 29, 2015 Georgia Power 20 years Approx. $46 (c) Butler CERSM, LLC and Community Energy, Inc. 103 Taylor Fourth quarter 2016 Georgia Power (b) 30 years $ 220 - 230 (c) Pawpaw Longview Solar, LLC 30 Taylor March 2016 Georgia Power (a) 30 years $ 70 - 80 (c) Butler Solar Farm Strata Solar Development, LLC 22 Taylor February 10, 2016 Georgia Power 20 years Approx. $45 (c) (a) Affiliate PPA approved by the FERC. (b) Affiliate PPA subject to FERC approval. (c) Includes the acquisition price of all outstanding membership interests of the respective development entity. |
Schedule of Business Acquisitions, by Acquisition | 2015 Project Facility Seller; Acquisition Date Approx. Location Southern Power Percentage Ownership Expected/Actual COD PPA for Plant Output PPA Approx. Purchase Price (MW) (in millions) WIND Kay Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 12, 2015 Westar Energy, Inc. and Grant River Dam Authority 20 years $ 481 (b) Grant Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % March 2016 Western Farmers, East Texas, and Northeast Texas Electric Cooperative 20 years $ 258 (c) SOLAR Lost Hills Blackwell First Solar, Inc. (First Solar) 33 Kern County, CA 51 % (a) April 17, 2015 City of Roseville, California/Pacific Gas and Electric Company 29 years $ 73 (d) North Star First Solar 61 Fresno County, CA 51 % (a) June 20, 2015 Pacific Gas and Electric Company 20 years $ 208 (e) Tranquillity Recurrent Energy, LLC 205 Fresno County, CA 51 % (a) Fourth quarter 2016 Shell Energy North America (US), LP and then Southern California Edison (SCE) 18 years $ 100 (f) Desert Stateline First Solar 299 San Bernardino County, CA 51 % (a) From December 2015 to third quarter 2016 (h) SCE 20 years $ 439 (g) Morelos Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % November 25, 2015 Pacific Gas and Electric Company 20 years $ 45 (i) Roserock Recurrent Energy, LLC 160 Pecos County, TX 51 % (a) Fourth quarter 2016 Austin Energy 20 years $ 45 (j) Garland and Garland A Recurrent Energy, LLC 205 Kern County, CA 51 % (a) Fourth quarter 2016 SCE 15 years $ 49 (k) Calipatria Solar Frontier Americas Holding, LLC 20 Imperial County, CA 90 % February 11, 2016 San Diego Gas & Electric Company 20 years $ 52 (l) (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. At each acquisition, Southern Power acquired a controlling interest in the entity owning the project facility and recorded approximately $227 million for the noncontrolling interests, in the aggregate, which is recorded as a non-cash transaction in contributions from noncontrolling interests and plant acquisitions. (b) Kay Wind - The total purchase price, including $35 million of contingent consideration, is approximately $481 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $481 million as CWIP, $8 million as a receivable related to transmission interconnection costs, and $8 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. (c) Grant Wind - On September 4, 2015, Southern Power entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at or near the expected COD. The purchase price includes approximately $24 million of contingent consideration and may be adjusted based on performance testing and production over the first 10 years of operation. The ultimate outcome of this matter cannot be determined at this time. (d) Lost Hills Blackwell - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $34 million . At the acquisition date, the members became contingently obligated to pay $3 million of construction payables through COD, making the aggregate purchase price approximately $107 million . The fair values of the assets acquired through the business combination were recorded as follows: $105 million as property, plant, and equipment, $3 million as a receivable related to transmission interconnection costs, and $4 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. (e) North Star - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $99 million . At the acquisition date, the members became contingently obligated to pay $233 million of construction payables through COD, making the aggregate purchase price approximately $307 million . The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $25 million as an intangible asset, $21 million as a receivable related to transmission interconnection costs, and $238 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The amortization expense for the year ended December 31, 2015 was $1 million . The estimated amortization for future periods is approximately $1.2 million per year for 2016 through 2020, and $18 million thereafter. (f) Tranquillity - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $173 million of assets and receiving an initial distribution of $100 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $186 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million . The ultimate outcome of this matter cannot be determined at this time. (g) Desert Stateline - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million . As of December 31, 2015, the fair values of the assets acquired through the business combination, which includes Southern Power's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion . The ultimate outcome of this matter cannot be determined at this time. (h) Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service. (i) Morelos - The total purchase price, including the minority owner, Turner Renewable Energy, LLC's (TRE) 10% ownership interest, is approximately $50 million . As of December 31, 2015, the fair values of the assets acquired through the business combination were recorded as follows: $49 million as property, plant, and equipment and $1 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. (j) Roserock - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $26 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $75 million as CWIP, $6 million as other receivables, and $10 million as payables and accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million . The ultimate outcome of this matter cannot be determined at this time. (k) Garland and Garland A - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $31 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $107 million as CWIP, $1 million as other deferred assets, and $28 million as payables and other accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million . The ultimate outcome of this matter cannot be determined at this time. (l) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $58 million . 2014 Project Seller; Acquisition Date Approx. Nameplate Capacity Location Southern Power Percentage Ownership COD PPA PPA Contract Period Approx. Purchase Price (MW) (in millions) SOLAR Adobe Sun Edison, LLC 20 Kern County, CA 90 % May 21, 2014 SCE 20 years $ 86 (b) Macho Springs First Solar Development, LLC 50 Luna County, NM 90 % May 23, 2014 El Paso Electric Company 20 years $ 117 (c) Imperial Valley First Solar, October 22, 2014 150 Imperial County, CA 51 % (a) November 26, 2014 San Diego Gas & Electric Company 25 years $ 505 (d) (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) Adobe - Total purchase price, including the minority owner TRE's 10% ownership interest, was $97 million . The fair values of the assets acquired were ultimately recorded as follows: $84 million to property, plant, and equipment, $15 million to prepayment related to transmission services, and $6 million to PPA intangible, resulting in a $5 million bargain purchase gain and a $3 million deferred tax liability. The bargain purchase gain is included in other income (expense), net. Acquisition-related costs were expensed as incurred and were not material. (c) Macho Springs - Total purchase price, including the minority owner TRE's 10% ownership interest, was $130 million . The fair values of the assets acquired were ultimately recorded as follows: $128 million to property, plant, and equipment, $1 million to prepaid property taxes, and $1 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material. (d) Imperial Valley - In connection with this acquisition, SG2 Holdings, LLC (SG2 Holdings) made an aggregate payment of approximately $128 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599 million upon completion of the facility (representing the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved in November 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by Southern Power for the acquisition of Imperial Valley was approximately $505 million in addition to the $223 million noncash contribution by the minority member. The fair values of the assets acquired were ultimately recorded as follows: $708 million to property, plant, and equipment and $20 million to prepayment related to transmission services. Acquisition-related costs were expensed as incurred and were not material. |
Southern Power [Member] | |
Business Acquisition [Line Items] | |
Schedule of Construction Projects | Construction Projects During 2015, in accordance with the Company's overall growth strategy, the Company constructed or commenced construction of the projects set forth in the table below, in addition to the Tranquillity, Desert Stateline, Roserock, Garland, and Garland A facilities. Total cost of construction incurred for these projects during 2015 was $1.8 billion , of which $1.1 billion remains in CWIP at December 31, 2015 . Solar Facility Seller Approx. Nameplate Capacity County Location in Georgia Expected/Actual COD PPA Counterparties PPA Contract Period Estimated Construction Cost (MW) (in millions) Sandhills N/A 146 Taylor Fourth quarter 2016 Cobb, Flint, and Sawnee EMCs 25 years $ 260 - 280 Decatur Parkway TradeWind Energy, Inc. 84 Decatur December 31, 2015 Georgia Power (a) 25 years Approx. $169 (c) Decatur County TradeWind Energy, Inc. 20 Decatur December 29, 2015 Georgia Power 20 years Approx. $46 (c) Butler CERSM, LLC and Community Energy, Inc. 103 Taylor Fourth quarter 2016 Georgia Power (b) 30 years $ 220 - 230 (c) Pawpaw Longview Solar, LLC 30 Taylor March 2016 Georgia Power (a) 30 years $ 70 - 80 (c) Butler Solar Farm Strata Solar Development, LLC 22 Taylor February 10, 2016 Georgia Power 20 years Approx. $45 (c) (a) Affiliate PPA approved by the FERC. (b) Affiliate PPA subject to FERC approval. (c) Includes the acquisition price of all outstanding membership interests of the respective development entity. |
Schedule of Business Acquisitions, by Acquisition | During 2015 and 2014, in accordance with the Company's overall growth strategy, the Company acquired or contracted to acquire through its wholly-owned subsidiaries, SRP or SRE, the projects set forth in the following table. Acquisition-related costs of approximately $4 million were expensed as incurred. The acquisitions do not include any contingent consideration unless specifically noted. 2015 Project Facility Seller; Acquisition Date Approx. Location Percentage Ownership Expected/Actual COD PPA PPA Approx. Purchase Price (MW) (in millions) WIND Kay Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 12, 2015 Westar Energy, Inc. and Grant River Dam Authority 20 years $ 481 (b) Grant Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % March 2016 Western Farmers, East Texas, and Northeast Texas Electric Cooperative 20 years $ 258 (c) SOLAR Lost Hills Blackwell First Solar 33 Kern County, CA 51 % (a) April 17, 2015 City of Roseville, California/Pacific Gas and Electric Company 29 years $ 73 (d) North Star First Solar 61 Fresno County, CA 51 % (a) June 20, 2015 Pacific Gas and Electric Company 20 years $ 208 (e) Tranquillity Recurrent Energy, LLC 205 Fresno County, CA 51 % (a) Fourth quarter 2016 Shell Energy North America (US), LP and then SCE 18 years $ 100 (f) Desert Stateline First Solar 299 San Bernardino County, CA 51 % (a) From December 2015 to third quarter 2016 (h) SCE 20 years $ 439 (g) Morelos Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % November 25, 2015 Pacific Gas and Electric Company 20 years $ 45 (i) Roserock Recurrent Energy, LLC 160 Pecos County, TX 51 % (a) Fourth quarter 2016 Austin Energy 20 years $ 45 (j) Garland and Garland A Recurrent Energy, LLC 205 Kern County, CA 51 % (a) Fourth quarter 2016 SCE 15 years 20 years $ 49 (k) Calipatria Solar Frontier Americas Holding, LLC 20 Imperial County, CA 90 % February 11, 2016 San Diego Gas & Electric Company 20 years $ 52 (l) (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. At each acquisition, the Company acquired a controlling interest in the entity owning the project facility and recorded approximately $227 million for the noncontrolling interests, in the aggregate, which is recorded as a non-cash transaction in contributions from noncontrolling interests and plant acquisitions. (b) Kay Wind - The total purchase price, including $35 million of contingent consideration, is approximately $481 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $481 million as CWIP, $8 million as a receivable related to transmission interconnection costs, and $8 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. (c) Grant Wind - On September 4, 2015, Southern Power entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at or near the expected COD. The purchase price includes approximately $24 million of contingent consideration and may be adjusted based on performance testing and production over the first 10 years of operation. The ultimate outcome of this matter cannot be determined at this time. (d) Lost Hills Blackwell - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $34 million . At the acquisition date, the members became contingently obligated to pay $3 million of construction payables through COD, making the aggregate purchase price approximately $107 million . The fair values of the assets acquired through the business combination were recorded as follows: $105 million as property, plant, and equipment, $3 million as a receivable related to transmission interconnection costs, and $4 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. (e) North Star - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $99 million . At the acquisition date, the members became contingently obligated to pay $233 million of construction payables through COD, making the aggregate purchase price approximately $307 million . The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $25 million as an intangible asset, $21 million as a receivable related to transmission interconnection costs, and $238 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The amortization expense for the year ended December 31, 2015 was $1 million . The estimated amortization for future periods is approximately $1.2 million per year for 2016 through 2020, and $18 million thereafter. (f) Tranquillity - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $173 million of assets and receiving an initial distribution of $100 million . As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $186 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million . The ultimate outcome of this matter cannot be determined at this time. (g) Desert Stateline - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million . As of December 31, 2015, the fair values of the assets acquired through the business combination, which includes the Company's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20 -year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion . The ultimate outcome of this matter cannot be determined at this time. (h) Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service. (i) Morelos - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $50 million . As of December 31, 2015, the fair values of the assets acquired through the business combination were recorded as follows: $49 million as property, plant, and equipment and $1 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. (j) Roserock - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $26 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $75 million as CWIP, $6 million as other receivables, and $10 million as payables and accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million . The ultimate outcome of this matter cannot be determined at this time. (k) Garland and Garland A - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $31 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $107 million as CWIP, $1 million as other deferred assets, and $28 million as payables and other accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million . The ultimate outcome of this matter cannot be determined at this time. (l) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $58 million . The aggregate amount of revenue recognized by to the Company related to the acquisitions, since the various acquisition dates, included in the consolidated statement of income for 2015 is $18 million . The aggregate amount of net income, excluding the impacts of ITCs, attributable to the Company related to the acquisitions, since the various acquisition dates, included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to their assets being constructed and placed in service; and therefore, supplemental proforma information as though the acquisitions occurred as of the beginning of 2015, and for the comparable 2014 year is not meaningful and has been omitted. 2014 Project Seller; Acquisition Date Approx. Nameplate Capacity Location Percentage Ownership COD PPA PPA Contract Period Approx. Purchase Price (MW) (in millions) SOLAR Adobe Sun Edison, LLC 20 Kern County, CA 90 % May 21, 2014 SCE 20 years $ 86 (b) Macho Springs First Solar Development, LLC 50 Luna County, NM 90 % May 23, 2014 EPE 20 years $ 117 (c) Imperial Valley First Solar, October 22, 2014 150 Imperial County, CA 51 % (a) November 26, 2014 San Diego Gas & Electric Company 25 years $ 505 (d) (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) Adobe - Total purchase price, including the minority owner TRE's 10% ownership interest, was $97 million . The fair values of the assets acquired were ultimately recorded as follows: $84 million to property, plant, and equipment, $15 million to prepayment related to transmission services, and $6 million to PPA intangible, resulting in a $5 million bargain purchase gain and a $3 million deferred tax liability. The bargain purchase gain is included in other income (expense), net. Acquisition-related costs were expensed as incurred and were not material. (c) Macho Springs - Total purchase price, including the minority owner TRE's 10% ownership interest, was $130 million . The fair values of the assets acquired were ultimately recorded as follows: $128 million to property, plant, and equipment, $1 million to prepaid property taxes, and $1 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material. (d) Imperial Valley - In connection with this acquisition, SG2 Holdings, LLC (SG2 Holdings) made an aggregate payment of approximately $128 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599 million upon completion of the facility (representing the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved in November 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by the Company for the acquisition of Imperial Valley was approximately $505 million in addition to the $223 million noncash contribution by the minority member. The fair values of the assets acquired were ultimately recorded as follows: $708 million to property, plant, and equipment and $20 million to prepayment related to transmission services. Acquisition-related costs were expensed as incurred and were not material. |
Contingencies and Regulatory 33
Contingencies and Regulatory Matters (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Loss Contingencies [Line Items] | |
Current cost estimate and actual costs incurred | Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of December 31, 2015 , are as follows: Cost Category 2010 Project Estimate (f) Current Cost Estimate (a) Actual Costs (in billions) Plant Subject to Cost Cap (b)(g) $ 2.40 $ 5.29 $ 4.83 Lignite Mine and Equipment 0.21 0.23 0.23 CO 2 Pipeline Facilities 0.14 0.11 0.11 AFUDC (c) 0.17 0.69 0.59 Combined Cycle and Related Assets Placed in Service – Incremental (d)(g) — 0.01 0.01 General Exceptions 0.05 0.10 0.09 Deferred Costs (e)(g) — 0.20 0.17 Total Kemper IGCC $ 2.97 $ 6.63 $ 6.03 (a) Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016. (b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information. (c) Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. (d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. (e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein. (f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO 2 pipeline facilities which was approved in 2011 by the Mississippi PSC. (g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015 . |
Mississippi Power [Member] | |
Loss Contingencies [Line Items] | |
Current cost estimate and actual costs incurred | The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of December 31, 2015 , are as follows: Cost Category 2010 Project Estimate (f) Current Cost Estimate (a) Actual Costs (in billions) Plant Subject to Cost Cap (b)(g) $ 2.40 $ 5.29 $ 4.83 Lignite Mine and Equipment 0.21 0.23 0.23 CO 2 Pipeline Facilities 0.14 0.11 0.11 AFUDC (c) 0.17 0.69 0.59 Combined Cycle and Related Assets Placed in Service – Incremental (d)(g) — 0.01 0.01 General Exceptions 0.05 0.10 0.09 Deferred Costs (e)(g) — 0.20 0.17 Total Kemper IGCC $ 2.97 $ 6.63 $ 6.03 (a) Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016. (b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information. (c) The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information. (d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. (e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein. (f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO 2 pipeline facilities which was approved in 2011 by the Mississippi PSC. (g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015. |
Joint Ownership Agreements (Tab
Joint Ownership Agreements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2015 , Alabama Power's, Georgia Power's, and Southern Power's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: Facility (Type) Percent Ownership Plant in Service Accumulated Depreciation CWIP (in millions) Plant Vogtle (nuclear) Units 1 and 2 45.7 % $ 3,503 $ 2,084 $ 63 Plant Hatch (nuclear) 50.1 1,230 568 90 Plant Miller (coal) Units 1 and 2 91.8 1,518 587 63 Plant Scherer (coal) Units 1 and 2 8.4 260 86 1 Plant Wansley (coal) 53.5 915 290 13 Rocky Mountain (pumped storage) 25.4 181 125 — Intercession City (combustion turbine) 33.3 13 4 — Plant Stanton (combined cycle) Unit A 65.0 157 53 — |
Alabama Power [Member] | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2015 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) $ 159 $ 97 $ 20 Plant Miller Units 1 and 2 1,320 91.84 % (2) 1,518 587 63 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth Energy Cooperative, Inc. |
Georgia Power [Member] | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2015 , 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 % $ 3,503 $ 2,084 $ 63 Plant Hatch (nuclear) 50.1 1,230 568 90 Plant Wansley (coal) 53.5 915 290 13 Plant Scherer (coal) Units 1 and 2 8.4 260 86 1 Unit 3 75.0 1,223 433 1 Rocky Mountain (pumped storage) 25.4 181 125 — Intercession City (combustion-turbine) 33.3 13 4 — |
Gulf Power [Member] | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2015 , 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 $ 395 $ 669 Accumulated depreciation 136 184 Construction work in progress 2 9 Company Ownership 25 % 50 % |
Mississippi Power [Member] | |
Jointly Owned Utility Plant Interests [Line Items] | |
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2015 , 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 % $ 152 $ 56 $ 13 Daniel Units 1 and 2 50 % $ 686 $ 160 $ 10 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current $ (177 ) $ 175 $ 363 Deferred 1,266 695 386 1,089 870 749 State — Current (33 ) 93 (10 ) Deferred 138 14 110 105 107 100 Total $ 1,194 $ 977 $ 849 |
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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation $ 12,767 $ 11,125 Property basis differences 1,543 1,332 Leveraged lease basis differences 308 299 Employee benefit obligations 579 613 Premium on reacquired debt 95 103 Regulatory assets associated with employee benefit obligations 1,378 1,390 Regulatory assets associated with AROs 1,422 871 Other 586 523 Total 18,678 16,256 Deferred tax assets — Federal effect of state deferred taxes 479 430 Employee benefit obligations 1,720 1,675 Over recovered fuel clause 104 — Other property basis differences 695 453 Deferred costs 83 86 ITC carryforward 742 480 Unbilled revenue 111 67 Other comprehensive losses 85 89 AROs 1,422 871 Estimated Loss on Kemper IGCC 451 631 Deferred state tax assets 220 117 Other 246 342 Total 6,358 5,241 Valuation allowance (2 ) (49 ) Total deferred tax assets 6,356 5,192 Accumulated deferred income taxes $ 12,322 $ 11,064 |
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 1.9 2.3 2.5 Employee stock plans dividend deduction (1.2 ) (1.4 ) (1.6 ) Non-deductible book depreciation 1.2 1.4 1.5 AFUDC-Equity (2.2 ) (2.9 ) (2.6 ) ITC basis difference (1.5 ) (1.6 ) (1.2 ) Other (0.3 ) (0.3 ) (0.5 ) Effective income tax rate 32.9 % 32.5 % 33.1 % |
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ 170 $ 7 $ 70 Tax positions increase from current periods 43 64 3 Tax positions increase from prior periods 240 102 — Tax positions decrease from prior periods (20 ) (3 ) (66 ) Balance at end of year $ 433 $ 170 $ 7 |
Impact on effective tax rate | The impact on Southern Company's effective tax rate, if recognized, is as follows: 2015 2014 2013 (in millions) Tax positions impacting the effective tax rate $ 10 $ 10 $ 7 Tax positions not impacting the effective tax rate 423 160 — Balance of unrecognized tax benefits $ 433 $ 170 $ 7 |
Alabama Power [Member] | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current $ 110 $ 198 $ 243 Deferred 320 225 160 430 423 403 State — Current 8 44 36 Deferred 68 45 39 76 89 75 Total $ 506 $ 512 $ 478 |
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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation $ 3,917 $ 3,429 Property basis differences 456 457 Premium on reacquired debt 28 30 Employee benefit obligations 200 215 Regulatory assets associated with employee benefit obligations 375 366 Asset retirement obligations 289 59 Regulatory assets associated with asset retirement obligations 312 285 Other 175 157 Total 5,752 4,998 Deferred tax assets — Federal effect of state deferred taxes 242 219 Unbilled fuel revenue 39 42 Storm reserve 23 27 Employee benefit obligations 407 400 Other comprehensive losses 20 19 Asset retirement obligations 600 344 Other 180 90 Total 1,511 1,141 Accumulated deferred income taxes, net $ 4,241 $ 3,857 |
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.8 4.4 4.0 Non-deductible book depreciation 1.2 1.1 1.0 Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.1) AFUDC equity (1.6) (1.3) (0.9) Other 0.1 (0.1) (0.1) Effective income tax rate 38.4% 39.0% 38.9% |
Georgia Power [Member] | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal – Current $ 515 $ 295 $ 277 Deferred 176 366 374 691 661 651 State – Current 81 82 (30 ) Deferred (3 ) (14 ) 102 78 68 72 Total $ 769 $ 729 $ 723 |
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: 2015 2014 (in millions) Deferred tax liabilities – Accelerated depreciation $ 4,909 $ 4,732 Property basis differences 943 811 Employee benefit obligations 310 329 Under-recovered fuel costs — 81 Premium on reacquired debt 61 66 Regulatory assets associated with employee benefit obligations 528 534 Asset retirement obligations 706 497 Other 187 160 Total 7,644 7,210 Deferred tax assets – Federal effect of state deferred taxes 150 148 Employee benefit obligations 642 642 Other property basis differences 88 86 Other deferred costs 83 86 Cost of removal obligations 6 11 State investment tax credit carryforward 188 152 Federal tax credit carryforward 3 5 Over-recovered fuel costs 45 — Unbilled fuel revenue 47 46 Asset retirement obligations 706 497 Other 59 63 Total 2,017 1,736 Accumulated deferred income taxes $ 5,627 $ 5,474 |
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.5 2.2 2.5 Non-deductible book depreciation 1.2 1.3 1.3 AFUDC equity (0.7) (0.8) (0.6) Other (0.4) (0.7) (0.4) Effective income tax rate 37.6% 37.0% 37.8% |
Changes in unrecognized tax benefits | Changes in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ — $ — $ 23 Tax positions increase from prior periods 3 — — Tax positions decrease from prior periods — — (23 ) Balance at end of year $ 3 $ — $ — |
Gulf Power [Member] | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal - Current $ (3 ) $ 23 $ 5 Deferred 80 52 63 77 75 68 State - Current 5 — (2 ) Deferred 10 13 14 15 13 12 Total $ 92 $ 88 $ 80 |
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: 2015 2014 (in millions) Deferred tax liabilities- Accelerated depreciation $ 812 $ 777 Property basis differences 133 52 Fuel recovery clause — 16 Pension and other employee benefits 39 34 Regulatory assets associated with employee benefit obligations 59 60 Regulatory assets associated with asset retirement obligations 40 7 Other 26 22 Total 1,109 968 Deferred tax assets- Federal effect of state deferred taxes 33 31 Postretirement benefits 26 18 Pension and other employee benefits 65 66 Property reserve 15 13 Asset retirement obligations 40 7 Alternative minimum tax carryforward 18 18 Other 19 18 Total 216 171 Accumulated deferred income taxes $ 893 $ 797 |
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.9 3.5 3.5 Non-deductible book depreciation 0.5 0.4 0.5 Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.2) AFUDC equity (1.8) (1.8) (1.1) Other, net (0.6) 0.1 (0.1) Effective income tax rate 36.9% 37.1% 37.6% |
Mississippi Power [Member] | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current $ (768 ) $ (431 ) $ 23 Deferred 704 183 (343 ) (64 ) (248 ) (320 ) State — Current (81 ) 1 5 Deferred 73 (38 ) (53 ) (8 ) (37 ) (48 ) Total $ (72 ) $ (285 ) $ (368 ) |
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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation $ 1,618 $ 1,068 ECM under recovered 13 — Regulatory assets associated with AROs 71 19 Pensions and other benefits 30 35 Regulatory assets associated with employee benefit obligations 66 68 Regulatory assets associated with the Kemper IGCC 86 62 Rate differential 115 89 Federal effect of state deferred taxes — 1 Fuel clause under recovered — 3 Other 163 52 Total 2,162 1,397 Deferred tax assets — Fuel clause over recovered 51 — Estimated loss on Kemper IGCC 451 631 Pension and other benefits 92 92 Property insurance 25 24 Premium on long-term debt 18 21 Unbilled fuel 16 15 AROs 71 19 Interest rate hedges 4 5 Kemper rate factor - regulatory liability retail — 108 Property basis difference 451 263 ECM over recovered — 1 Deferred state tax assets 152 57 Deferred federal tax assets 48 — Federal effect of state deferred taxes 8 — Other 13 15 Total 1,400 1,251 Total deferred tax liabilities, net 762 146 Deferred state tax asset — 34 Accumulated deferred income taxes $ 762 $ 180 |
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate (35.0 )% (35.0 )% (35.0 )% State income tax, net of federal deduction (6.3 ) (4.0 ) (3.7 ) Non-deductible book depreciation 1.3 0.1 0.1 AFUDC-equity (49.6 ) (7.8 ) (5.0 ) Other (2.9 ) 0.1 (0.1 ) Effective income tax rate (benefit rate) (92.5 )% (46.6 )% (43.7 )% |
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ 165 $ 4 $ 6 Tax positions increase from current periods 32 58 — Tax positions increase/(decrease) from prior periods 224 103 (2 ) Balance at end of year $ 421 $ 165 $ 4 |
Impact on effective tax rate | The impact on the Company's effective tax rate, if recognized, is as follows: 2015 2014 2013 (in millions) Tax positions impacting the effective tax rate $ (2 ) $ 4 $ 4 Tax positions not impacting the effective tax rate 423 161 — Balance of unrecognized tax benefits $ 421 $ 165 $ 4 |
Accrued interest for unrecognized tax benefits | Accrued interest for unrecognized tax benefits was as follows: 2015 2014 2013 (in millions) Interest accrued at beginning of year $ 3 $ 1 $ 1 Interest accrued during the year 6 2 — Balance at end of year $ 9 $ 3 $ 1 |
Southern Power [Member] | |
Income Tax Disclosure [Line Items] | |
Details of income tax provisions | Details of income tax provisions are as follows: 2015 2014 2013 (in millions) Federal — Current (*) $ 12 $ 179 $ (120 ) Deferred (*) 10 (166 ) 159 22 13 39 State — Current (32 ) (14 ) (5 ) Deferred 31 (2 ) 12 (1 ) (16 ) 7 Total $ 21 $ (3 ) $ 46 (*) ITCs 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 the federal income tax expense above. ITCs reclassified in this manner include $246 million for 2015 and $305 million for 2014. These ITCs 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: 2015 2014 (in millions) Deferred tax liabilities — Accelerated depreciation and other property basis differences $ 1,364 $ 1,006 Basis difference on asset transfers 3 3 Levelized capacity revenues 22 17 Other 4 6 Total 1,393 1,032 Deferred tax assets — Federal effect of state deferred taxes 40 29 Net basis difference on federal ITCs 149 102 Alternative minimum tax carryforward 15 15 Unrealized tax credits 551 305 Unrealized loss on interest rate swaps 4 6 Levelized capacity revenues 4 5 Deferred state tax assets 13 15 Other 18 4 Total 794 481 Valuation Allowance (2 ) (8 ) Net deferred income tax assets 792 473 Accumulated deferred income taxes $ 601 $ 559 |
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction (0.3 ) (6.0 ) 2.2 Amortization of ITC (5.0 ) (4.3 ) (1.7 ) ITC basis difference (21.5 ) (27.7 ) (14.5 ) Other 0.2 1.1 0.3 Effective income tax rate 8.4 % (1.9 )% 21.3 % |
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: 2015 2014 2013 (in millions) Unrecognized tax benefits at beginning of year $ 5 $ 2 $ 3 Tax positions increase from current periods 9 5 2 Tax positions decrease from prior periods (6 ) (2 ) (3 ) Balance at end of year $ 8 $ 5 $ 2 |
Financing (Tables)
Financing (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Line Items] | |
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: 2015 2014 (in millions) Senior notes $ 1,810 $ 2,375 Other long-term debt 829 775 Pollution control revenue bonds 4 152 Capitalized leases 32 31 Unamortized debt issuance expense (1 ) (4 ) Total $ 2,674 $ 3,329 |
Credit arrangements with banks | At December 31, 2015 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Due Within One Year Company 2016 2017 2018 2020 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) Southern Company (a) $ — $ — $ 1,000 $ 1,250 $ 2,250 $ 2,250 $ — $ — $ — $ — Alabama Power 40 — 500 800 1,340 1,340 — — — 40 Georgia Power — — — 1,750 1,750 1,732 — — — — Gulf Power 80 30 165 — 275 275 50 — 50 30 Mississippi Power 220 — — — 220 195 30 15 45 175 Southern Power (b) — — — 600 600 566 — — — — Other 70 — — — 70 70 — — — 70 Total $ 410 $ 30 $ 1,665 $ 4,400 $ 6,505 $ 6,428 $ 80 $ 15 $ 95 $ 315 |
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, 2015: Commercial paper $ 740 0.7 % Short-term bank debt 500 1.4 % Total $ 1,240 0.9 % December 31, 2014: Commercial paper $ 803 0.3 % Short-term bank debt — — % Total $ 803 0.3 % |
Alabama Power [Member] | |
Debt Disclosure [Line Items] | |
Credit arrangements with banks | At December 31, 2015 , committed credit arrangements with banks were as follows: Expires Due Within One Year 2016 2018 2020 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) $ 40 $ 500 $ 800 $ 1,340 $ 1,340 $ — $ 40 |
Georgia Power [Member] | |
Debt Disclosure [Line Items] | |
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows: 2015 2014 (in millions) Senior notes $ 700 $ 1,050 Pollution control revenue bonds 4 98 Capital lease 8 6 Unamortized debt issuance expense — (4 ) Total $ 712 $ 1,150 |
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, 2015: Commercial paper $ 158 0.6 % December 31, 2014: Commercial paper $ 156 0.3 % |
Gulf Power [Member] | |
Debt Disclosure [Line Items] | |
Credit arrangements with banks | At December 31, 2015 , committed credit arrangements with banks were as follows: Expires Executable Term-Loans Due Within One Year 2016 2017 2018 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $ 80 $ 30 $ 165 $ 275 $ 275 $ 50 $ — $ 50 $ 30 |
Short-term borrowings | Details of short-term borrowings were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2015 $ 142 0.7% December 31, 2014 $ 110 0.3% |
Mississippi Power [Member] | |
Debt Disclosure [Line Items] | |
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2015 and 2014 was as follows: 2015 2014 (in millions) Senior notes $ 300 $ — Bank term loans 425 775 Capitalized leases 3 3 Outstanding at December 31 $ 728 $ 778 |
Credit arrangements with banks | At December 31, 2015 , committed credit arrangements with banks were as follows: Expires Executable Term-Loans Due Within One Year 2016 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $220 $220 $195 $30 $15 $45 $175 |
Southern Power [Member] | |
Debt Disclosure [Line Items] | |
Credit arrangements with banks | The table below summarizes each Project Credit Facility as of December 31, 2015 . Project Maturity Date Construction Loan Facility Bridge Loan Facility Total Total Undrawn Letter of Credit Facility Total Undrawn (in millions) Tranquillity Earlier of COD or December 31, 2016 $ 86 $ 172 $ 258 $ 147 $ 77 $ 26 Roserock Earlier of COD or November 30, 2016 63 180 243 243 23 23 Garland Earlier of COD or November 30, 2016 86 308 394 368 49 32 Total $ 235 $ 660 $ 895 $ 758 $ 149 $ 81 |
Short-term borrowings | Commercial paper is included in notes payable in the balance sheets as noted below: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2015 $ — N/A December 31, 2014 $ 195 0.4 % |
Redeemable Preferred Stock [Member] | Alabama Power [Member] | |
Debt Disclosure [Line Items] | |
Redeemable preferred stock | Information for each outstanding series is in the table below: Preferred/Preference Stock Par Value/Stated Capital Per Share Shares Outstanding Redemption Price Per Share 4.92% Preferred Stock $100 80,000 $103.23 4.72% Preferred Stock $100 50,000 $102.18 4.64% Preferred Stock $100 60,000 $103.14 4.60% Preferred Stock $100 100,000 $104.20 4.52% Preferred Stock $100 50,000 $102.93 4.20% Preferred Stock $100 135,115 $105.00 5.83% Class A Preferred Stock $25 1,520,000 Stated Capital 6.450% Preference Stock $25 6,000,000 * 6.500% Preference Stock $25 2,000,000 * * Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital |
Redeemable Preferred Stock [Member] | Mississippi Power [Member] | |
Debt Disclosure [Line Items] | |
Redeemable preferred 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 $ 25 1,200,000 $ 25.00 |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Estimated total obligations under these commitments at December 31, 2015 were as follows: Operating Leases (*) Other (in millions) 2016 $ 233 $ 10 2017 242 8 2018 246 7 2019 249 8 2020 246 4 2021 and thereafter 1,291 47 Total $ 2,507 $ 84 (*) A total of $304 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. |
Estimated minimum lease payments under operating leases | As of December 31, 2015 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2016 $ 40 $ 81 $ 121 2017 25 78 103 2018 14 67 81 2019 6 55 61 2020 6 47 53 2021 and thereafter 16 690 706 Total $ 107 $ 1,018 $ 1,125 |
Alabama Power [Member] | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Total estimated minimum long-term obligations at December 31, 2015 were as follows: Operating Lease PPAs (in millions) 2016 $ 39 2017 40 2018 41 2019 43 2020 44 2021 and thereafter 93 Total commitments $ 300 |
Estimated minimum lease payments under operating leases | As of December 31, 2015, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Vehicles & Other Total (in millions) 2016 $ 13 $ 6 $ 19 2017 8 5 13 2018 5 4 9 2019 5 4 9 2020 5 4 9 2021 and thereafter 13 — 13 Total $ 49 $ 23 $ 72 |
Georgia Power [Member] | |
Commitments [Line Items] | |
Estimated long-term obligations | Estimated total long-term obligations at December 31, 2015 were as follows: Affiliate Capital Leases Affiliate Operating Leases Non-Affiliate Operating Leases (4) Vogtle Units 1 and 2 Capacity Payments Total ($) (in millions) 2016 $ 22 $ 99 $ 115 $ 10 $ 246 2017 22 71 123 8 224 2018 22 62 126 7 217 2019 23 63 127 8 221 2020 23 64 123 4 214 2021 and thereafter 227 538 1,007 47 1,819 Total $ 339 $ 897 $ 1,621 $ 84 $ 2,941 Less: amounts representing executory costs (1) 54 Net minimum lease payments 285 Less: amounts representing interest (2) 84 Present value of net minimum lease payments (3) $ 201 (1) Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) a re estimated and included in total minimum lease payments. (2) Amount necessary to reduce minimum lease payments to present value calculated at the Company's incremental borrowing rate at the inception of the leases. (3) Once service commenced under the PPAs beginning in 2015, the Company recognized capital lease assets and capital lease obligations totaling $149 million , being the lesser of the estimated fair value of the lease property or the present value of the net minimum lease payments. (4) A total of $304 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. |
Estimated minimum lease payments under operating leases | As of December 31, 2015, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Other Total (in millions) 2016 $ 15 $ 8 $ 23 2017 10 8 18 2018 5 7 12 2019 1 7 8 2020 1 6 7 2021 and thereafter 3 13 16 Total $ 35 $ 49 $ 84 |
Gulf Power [Member] | |
Commitments [Line Items] | |
Estimated minimum long-term purchase commitments | Estimated total minimum long-term commitments at December 31, 2015 were as follows: Operating Lease PPAs (in millions) 2016 $ 79 2017 79 2018 79 2019 79 2020 79 2021 and thereafter 191 Total $ 586 |
Estimated minimum lease payments under operating leases | Estimated total minimum lease payments under these operating leases at December 31, 2015 were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2016 $ 9 $ 1 $ 10 2017 6 1 7 2018 4 — 4 Total $ 19 $ 2 $ 21 |
Common Stock and Stock Compen38
Common Stock and Stock Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted | The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 2014 2013 Expected volatility 14.6% 16.6% Expected term (in years) 5 5 Interest rate 1.5% 0.9% Dividend yield 4.9% 4.4% Weighted average grant-date fair value $2.20 $2.93 |
Summary of stock option activity | Southern Company's activity in the stock option program for 2015 is summarized below: Shares Subject to Option Weighted Average Exercise Price Outstanding at December 31, 2014 39,929,319 $40.55 Exercised 4,032,729 36.84 Cancelled 146,684 42.31 Outstanding at December 31, 2015 35,749,906 $40.96 Exercisable at December 31, 2015 25,857,590 $40.53 |
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 2015 2014 2013 Expected volatility 12.9% 12.6% 12.0% Expected term (in years) 3 3 3 Interest rate 1.0% 0.6% 0.4% Annualized dividend rate (*) N/A $2.03 $1.96 Weighted average grant-date fair value $46.38 $37.54 $40.50 (*) Beginning in 2015, cash dividends paid on Southern Company's common stock are accumulated and payable in additional shares of Southern Company's common stock at the end of the three-year performance period and are embedded in the grant date fair value which equates to the grant date stock price. |
Earnings per share | Shares used to compute diluted earnings per share were as follows: Average Common Stock Shares 2015 2014 2013 (in millions) As reported shares 910 897 877 Effect of options and performance share award units 4 4 4 Diluted shares 914 901 881 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 7 $ — $ — $ 7 Interest rate derivatives — 22 — — 22 Nuclear decommissioning trusts:(*) Domestic equity 541 69 — — 610 Foreign equity 47 160 — — 207 U.S. Treasury and government agency securities — 152 — — 152 Municipal bonds — 64 — — 64 Corporate bonds 11 278 — — 289 Mortgage and asset backed securities — 145 — — 145 Private equity — — — 17 17 Other 16 9 — — 25 Cash equivalents 790 — — — 790 Other investments 9 — 1 — 10 Total $ 1,414 $ 906 $ 1 $ 17 $ 2,338 Liabilities: Energy-related derivatives $ — $ 220 $ — $ — $ 220 Interest rate derivatives — 30 — — 30 Total $ — $ 250 $ — $ — $ 250 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 13 $ — $ — $ 13 Interest rate derivatives — 8 — — 8 Nuclear decommissioning trusts:(*) Domestic equity 583 85 — — 668 Foreign equity 34 184 — — 218 U.S. Treasury and government agency securities — 130 — — 130 Municipal bonds — 62 — — 62 Corporate bonds — 299 — — 299 Mortgage and asset backed securities — 139 — — 139 Private equity — — — 3 3 Other 11 13 — — 24 Cash equivalents 397 — — — 397 Other investments 9 — 1 — 10 Total $ 1,034 $ 933 $ 1 $ 3 $ 1,971 Liabilities: Energy-related derivatives $ — $ 201 $ — $ — $ 201 Interest rate derivatives — 24 — — 24 Total $ — $ 225 $ — $ — $ 225 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. |
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2015 and 2014 , 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, 2015 $ 17 $ 28 Not Applicable Not Applicable As of December 31, 2014 $ 3 $ 7 Not Applicable Not Applicable |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2015 and 2014 , 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: 2015 $ 27,216 $ 27,913 2014 $ 23,814 $ 25,816 |
Alabama Power [Member] | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2015, 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, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 1 $ — $ — $ 1 Nuclear decommissioning trusts: (*) Domestic equity 359 68 — — 427 Foreign equity 47 47 — — 94 U.S. Treasury and government agency securities — 27 — — 27 Corporate bonds 11 135 — — 146 Mortgage and asset backed securities — 18 — — 18 Private equity — — — 17 17 Other — 5 — — 5 Cash equivalents 68 — — — 68 Total $ 485 $ 301 $ — $ 17 $ 803 Liabilities: Interest rate derivatives $ — $ 15 $ — $ — $ 15 Energy-related derivatives — 55 — — 55 Total $ — $ 70 $ — $ — $ 70 (*) 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, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 1 $ — $ — $ 1 Nuclear decommissioning trusts: (*) Domestic equity 403 83 — — 486 Foreign equity 34 63 — — 97 U.S. Treasury and government agency securities — 34 — — 34 Corporate bonds — 111 — — 111 Mortgage and asset backed securities — 18 — — 18 Private equity — — — 3 3 Other — 5 — — 5 Cash equivalents 162 — — — 162 Total $ 599 $ 315 $ — $ 3 $ 917 Liabilities: Interest rate derivatives $ — $ 8 $ — $ — $ 8 Energy-related derivatives — 53 — — 53 Total $ — $ 61 $ — $ — $ 61 (*) 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, 2015 and 2014 , 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, 2015 $ 17 $ 28 Not Applicable Not Applicable As of December 31, 2014 $ 3 $ 7 Not Applicable Not Applicable |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2015 and 2014 , 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: 2015 $ 6,849 $ 7,192 2014 $ 6,586 $ 7,321 |
Georgia Power [Member] | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 2 $ — $ 2 Interest rate derivatives — 5 — 5 Nuclear decommissioning trusts:(*) Domestic equity 182 1 — 183 Foreign equity — 113 — 113 U.S. Treasury and government agency securities — 125 — 125 Municipal bonds — 64 — 64 Corporate bonds — 143 — 143 Mortgage and asset backed securities — 127 — 127 Other 16 4 — 20 Cash equivalents 63 — — 63 Total $ 261 $ 584 $ — $ 845 Liabilities: Energy-related derivatives $ — $ 15 $ — $ 15 Interest rate derivatives — 6 — 6 Total $ — $ 21 $ — $ 21 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 7 $ — $ 7 Interest rate derivatives — 6 — 6 Nuclear decommissioning trusts:(*) Domestic equity 180 2 — 182 Foreign equity — 121 — 121 U.S. Treasury and government agency securities — 96 — 96 Municipal bonds — 62 — 62 Corporate bonds — 188 — 188 Mortgage and asset backed securities — 121 — 121 Other 11 8 — 19 Total $ 191 $ 611 $ — $ 802 Liabilities: Energy-related derivatives $ — $ 27 $ — $ 27 Interest rate derivatives — 14 — 14 Total $ — $ 41 $ — $ 41 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2015 and 2014 , 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: 2015 $ 10,145 $ 10,480 2014 $ 9,673 $ 10,552 |
Gulf Power [Member] | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Interest rate derivatives $ — $ 1 $ — $ 1 Cash equivalents 18 — — 18 Total $ 18 $ 1 $ — $ 19 Liabilities: Energy-related derivatives $ — $ 100 $ — $ 100 As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 18 $ — $ — $ 18 Liabilities: Energy-related derivatives $ — $ 72 $ — $ 72 |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2015 and 2014 , 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: 2015 $ 1,303 $ 1,339 2014 $ 1,362 $ 1,477 |
Mississippi Power [Member] | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 52 $ — $ — $ 52 Liabilities: Energy-related derivatives $ — $ 47 $ — $ 47 As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 115 $ — $ — $ 115 Liabilities: Energy-related derivatives $ — $ 45 $ — $ 45 |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2015 and 2014 , 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: 2015 $ 2,537 $ 2,413 2014 $ 2,320 $ 2,382 |
Southern Power [Member] | |
Fair Value Disclosures [Line Items] | |
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2015 , 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, 2015: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 4 $ — $ 4 Interest rate derivatives — 3 — 3 Cash equivalents 511 — — 511 Total $ 511 $ 7 $ — $ 518 Liabilities: Energy-related derivatives $ — $ 3 $ — $ 3 As of December 31, 2014 , 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, 2014: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 5 $ — $ 5 Cash equivalents 18 — — 18 Total $ 18 $ 5 $ — $ 23 Liabilities: Energy-related derivatives $ — $ 4 $ — $ 4 |
Financial instruments not having carrying amount equal to fair value | As of December 31, 2015 and 2014 , 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: 2015 $ 3,122 $ 3,117 2014 $ 1,610 $ 1,785 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2015 , the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value Gain (Loss) December 31, 2015 (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 1,000 3-month LIBOR 2.37% November 2026 $ 1 1,000 3-month LIBOR 2.70% November 2046 (1 ) 200 3-month LIBOR 2.93% October 2025 (15 ) 80 3-month LIBOR 2.32% December 2026 1 Cash Flow Hedges of Existing Debt 250 3-month LIBOR + 0.32% 0.75% March 2016 — 200 3-month LIBOR + 0.40% 1.01% August 2016 — Fair Value Hedges of Existing Debt 250 1.30% 3-month LIBOR + 0.17% August 2017 1 300 2.75% 3-month LIBOR + 0.92% June 2020 2 250 5.40% 3-month LIBOR + 4.02% June 2018 1 200 4.25% 3-month LIBOR + 2.46% December 2019 2 500 1.95% 3-month LIBOR + 0.76% December 2018 (3 ) Derivatives not Designated as Hedges 65 (a,d) 3-month LIBOR 2.50% October 2016 (e) 1 47 (b,d) 3-month LIBOR 2.21% October 2016 (e) 1 65 (c,d) 3-month LIBOR 2.21% November 2016 (f) 1 Total $ 4,407 $ (8 ) ( a) Swaption at RE Tranquillity LLC. See Note 12 for additional information. ( b) Swaption at RE Roserock LLC. See Note 12 for additional information. ( c) Swaption at RE Garland Holdings LLC. See Note 12 for additional information. (d) Amortizing notional amount. (e) Represents the mandatory settlement date. Settlement amount will be based on a 15 -year amortizing swap. (f) Represents the mandatory settlement date. Settlement amount will be based on a 12 -year amortizing swap. |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ 3 $ 7 Liabilities from risk management activities $ 130 $ 118 Other deferred charges and assets — — Other deferred credits and liabilities 87 79 Total derivatives designated as hedging instruments for regulatory purposes $ 3 $ 7 $ 217 $ 197 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets $ 3 $ — Liabilities from risk management activities $ 2 $ — Interest rate derivatives: Other current assets 19 7 Liabilities from risk management activities 23 17 Other deferred charges and assets — 1 Other deferred credits and liabilities 7 7 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 22 $ 8 $ 32 $ 24 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets $ 1 $ 6 Liabilities from risk management activities $ 1 $ 4 Interest rate derivatives: Other current assets 3 — Liabilities from risk management activities — — Total derivatives not designated as hedging instruments $ 4 $ 6 $ 1 $ 4 Total $ 29 $ 21 $ 250 $ 225 |
Balance sheet offsetting | Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 7 $ 13 Energy-related derivatives presented in the Balance Sheet (a) $ 220 $ 201 Gross amounts not offset in the Balance Sheet (b) (6 ) (9 ) Gross amounts not offset in the Balance Sheet (b) (6 ) (9 ) Net energy-related derivative assets $ 1 $ 4 Net energy-related derivative liabilities $ 214 $ 192 Interest rate derivatives presented in the Balance Sheet (a) $ 22 $ 8 Interest rate derivatives presented in the Balance Sheet (a) $ 30 $ 24 Gross amounts not offset in the Balance Sheet (b) (9 ) (8 ) Gross amounts not offset in the Balance Sheet (b) (9 ) (8 ) Net interest rate derivative assets $ 13 $ — Net interest rate derivative liabilities $ 21 $ 16 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
Pre-tax effects on the balance sheets | At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (130 ) $ (118 ) Other regulatory liabilities, current $ 3 $ 7 Other regulatory assets, deferred (87 ) (79 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (217 ) $ (197 ) $ 3 $ 7 |
Pre-tax effects on the statements of income | For the years ended December 31, 2015 , 2014 , and 2013 , 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 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ (22 ) $ (16 ) $ — Interest expense, net of amounts capitalized $ (9 ) $ (8 ) $ (14 ) |
Alabama Power [Member] | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2015 , the following interest rate derivative was outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 200 3-month 2.93% October 2025 $ (15 ) |
Energy-related derivative contracts | At December 31, 2015 , the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Net Purchased mmBtu Longest Hedge Date Longest Non-Hedge Date (in millions) 50 2018 — |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ 1 $ 1 Liabilities from risk management activities $ 40 $ 32 Other deferred charges and assets — — Other deferred credits and liabilities 15 21 Total derivatives designated as hedging instruments for regulatory purposes $ 1 $ 1 $ 55 $ 53 Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets $ — $ — Liabilities from risk management activities $ 15 $ 8 Total $ 1 $ 1 $ 70 $ 61 |
Balance sheet offsetting | Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure table below. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 1 $ 1 Energy-related derivatives presented in the Balance Sheet (a) $ 55 $ 53 Gross amounts not offset in the Balance Sheet (b) (1 ) — Gross amounts not offset in the Balance Sheet (b) (1 ) — Net energy-related derivative assets $ — $ 1 Net energy-related derivative liabilities $ 54 $ 53 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
Pre-tax effects on the balance sheets | At December 31, 2015 and 2014 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (40 ) $ (32 ) Other current liabilities $ 1 $ 1 Other regulatory assets, deferred (15 ) (21 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (55 ) $ (53 ) $ 1 $ 1 |
Pre-tax effects on the statements of income | For the years ended December 31, 2015 , 2014 , and 2013 , 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 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ (7 ) $ (8 ) $ — Interest expense, net of amounts capitalized $ (3 ) $ (3 ) $ (3 ) |
Georgia Power [Member] | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2015 , 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 $ 250 3-month LIBOR + 0.32% 0.75% March 2016 $ — 200 3-month LIBOR + 0.40% 1.01% August 2016 — Fair Value Hedges of Existing Debt 250 5.40% 3-month LIBOR + 4.02% June 2018 1 200 4.25% 3-month LIBOR + 2.46% December 2019 2 500 1.95% 3-month LIBOR + .76% December 2018 (3 ) Total $ 1,400 $ — |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ 2 $ 6 Liabilities from risk management activities $ 12 $ 23 Other deferred charges and assets — 1 Other deferred credits and liabilities 3 4 Total derivatives designated as hedging instruments for regulatory purposes $ 2 $ 7 $ 15 $ 27 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets $ 5 $ 5 Liabilities from risk management activities $ — $ 9 Other deferred charges and assets — 1 Other deferred credits and liabilities 6 5 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 5 $ 6 $ 6 $ 14 Total $ 7 $ 13 $ 21 $ 41 |
Balance sheet offsetting | Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2015 and 2014 are presented in the following tables. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 2 $ 7 Energy-related derivatives presented in the Balance Sheet (a) $ 15 $ 27 Gross amounts not offset in the Balance Sheet (b) (2 ) (7 ) Gross amounts not offset in the Balance Sheet (b) (2 ) (7 ) Net energy-related derivative assets $ — $ — Net energy-related derivative liabilities $ 13 $ 20 Interest rate derivatives presented in the Balance Sheet (a) $ 5 $ 6 Interest rate derivatives presented in the Balance Sheet (a) $ 6 $ 14 Gross amounts not offset in the Balance Sheet (b) (4 ) (6 ) Gross amounts not offset in the Balance Sheet (b) (4 ) (6 ) Net interest rate derivative assets $ 1 $ — Net interest rate derivative liabilities $ 2 $ 8 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
Pre-tax effects on the balance sheets | At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (12 ) $ (23 ) Other regulatory liabilities, current $ 2 $ 6 Other regulatory assets, deferred (3 ) (4 ) Other deferred credits and liabilities — 1 Total energy-related derivative gains (losses) $ (15 ) $ (27 ) $ 2 $ 7 |
Pre-tax effects on the statements of income | For the years ended December 31, 2015 , 2014 , and 2013 , 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 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ (15 ) $ (8 ) $ — Interest expense, net of amounts capitalized $ (3 ) $ (3 ) $ (3 ) |
Gulf Power [Member] | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2015 , the following interest rate derivative was outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 80 3-month LIBOR 2.32% December 2026 $ 1 |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ — $ — Liabilities from risk management activities $ 49 $ 37 Other deferred charges and assets — — Other deferred credits and liabilities 51 35 Total derivatives designated as hedging instruments for regulatory purposes $ — $ — $ 100 $ 72 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets $ 1 $ — Liabilities from risk management activities $ — $ — Total $ 1 $ — $ 100 $ 72 |
Balance sheet offsetting | interest rate derivatives presented in the tables above do not have amounts available for offset. |
Pre-tax effects on the balance sheets | At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (49 ) $ (37 ) Other regulatory liabilities, current $ — $ — Other regulatory assets, deferred (51 ) (35 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (100 ) $ (72 ) $ — $ — |
Pre-tax effects on the statements of income | For the years ended December 31, 2015 , 2014 , and 2013 , 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 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) (Effective Portion) Amount Derivative Category 2015 2014 2013 Statements of Income Location 2015 2014 2013 (in millions) (in millions) Interest rate derivatives $ 1 $ — $ — Interest expense, net of amounts capitalized $ (1 ) $ (1 ) $ (1 ) |
Mississippi Power [Member] | |
Derivative [Line Items] | |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2015 and 2014 , the fair value of energy-related derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets $ — $ — Other current liabilities $ 29 $ 26 Other deferred charges and assets — — Other deferred credits and liabilities 18 19 Total derivatives designated as hedging instruments for regulatory purposes $ — $ — $ 47 $ 45 |
Balance sheet offsetting | energy-related derivatives presented in the table above did not have amounts available for offset. |
Pre-tax effects on the balance sheets | At December 31, 2015 and 2014 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (29 ) $ (26 ) Other regulatory liabilities, current $ — $ — Other regulatory assets, deferred (18 ) (19 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (47 ) $ (45 ) $ — $ — |
Pre-tax effects on the statements of income | For the years ended December 31, 2015 , 2014 , and 2013 , the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were immaterial. |
Southern Power [Member] | |
Derivative [Line Items] | |
Notional amount of interest rate derivatives | At December 31, 2015 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Derivatives not Designated as Hedges $ 65 (a,d) 3-month LIBOR 2.50% October 2016 (e) $ 1 47 (b.d) 3-month LIBOR 2.21% October 2016 (e) 1 65 (c,d) 3-month LIBOR 2.21% November 2016 (f) 1 Total $ 177 $ 3 (a) Swaption at RE Tranquillity LLC. See Note 2 for additional information. (b) Swaption at RE Roserock LLC. See Note 2 for additional information. (c) Swaption at RE Garland Holdings LLC. See Note 2 for additional information. (d) Amortizing notional amount. (e) Represents the mandatory settlement date. Settlement amount will be based on a 15 -year amortizing swap. (f) Represents the mandatory settlement date. Settlement amount will be based on a 12 -year amortizing swap. |
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2015 and 2014 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Asset Derivatives Liability Derivatives Derivative Category Balance Sheet Location 2015 2014 Balance Sheet Location 2015 2014 (in millions) (in millions) Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities $ 3 $ — Other current liabilities $ 2 $ — Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities $ 1 $ 5 Other current liabilities $ 1 $ 4 Interest rate derivatives: Assets from risk management activities 3 — Other current liabilities — — Total derivatives not designated as hedging instruments $ 4 $ 5 $ 1 $ 4 Total $ 7 $ 5 $ 3 $ 4 |
Balance sheet offsetting | Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below. Fair Value Assets 2015 2014 Liabilities 2015 2014 (in millions) (in millions) Energy-related derivatives presented in the Balance Sheet (a) $ 4 $ 5 Energy-related derivatives presented in the Balance Sheet (a) $ 3 $ 4 Gross amounts not offset in the Balance Sheet (b) (1 ) — Gross amounts not offset in the Balance Sheet (b) (1 ) — Net energy-related derivative assets $ 3 $ 5 Net energy-related derivative liabilities $ 2 $ 4 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
Pre-tax effects on the statements of income | For the years ended December 31, 2015 , 2014 , and 2013 , 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) Reclassified from AOCI into Income (Effective Portion) Amount Derivative Category Statements of Income Location 2015 2014 2013 (in millions) Interest rate derivatives Interest expense, net of amounts capitalized $ (1 ) $ (1 ) $ (6 ) |
Segment and Related Informati41
Segment and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Financial data for business segments | Financial data for business segments and products and services for the years ended December 31, 2015 , 2014 , and 2013 was as follows: Electric Utilities Traditional Operating Companies Southern Power Eliminations Total All Other Eliminations Consolidated (in millions) 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 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 2014 Operating revenues $ 17,354 $ 1,501 $ (449 ) $ 18,406 $ 159 $ (98 ) $ 18,467 Depreciation and amortization 1,709 220 — 1,929 16 — 1,945 Interest income 17 1 — 18 3 (2 ) 19 Interest expense 705 89 — 794 43 (2 ) 835 Income taxes 1,056 (3 ) — 1,053 (76 ) — 977 Segment net income (loss) (a) (b) 1,797 172 — 1,969 (3 ) (3 ) 1,963 Total assets (c) 64,300 5,233 (131 ) 69,402 1,143 (312 ) 70,233 Gross property additions 5,568 942 — 6,510 11 1 6,522 2013 Operating revenues $ 16,136 $ 1,275 $ (376 ) $ 17,035 $ 139 $ (87 ) $ 17,087 Depreciation and amortization 1,711 175 — 1,886 15 — 1,901 Interest income 17 1 — 18 2 (1 ) 19 Interest expense 714 74 — 788 36 — 824 Income taxes 889 46 — 935 (85 ) (1 ) 849 Segment net income (loss) (a) (b) 1,486 166 — 1,652 (10 ) 2 1,644 Total assets (c) 59,188 4,417 (101 ) 63,504 1,064 (304 ) 64,264 Gross property additions 5,226 633 — 5,859 9 — 5,868 (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $365 million ( $226 million after tax) in 2015, $868 million ( $536 million after tax) in 2014, and $1.2 billion ( $729 million after tax) in 2013. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. (c) Net of $202 million and $139 million of unamortized debt issuance costs as of December 31, 2014 and 2013, respectively. Also net of $488 million and $143 million of deferred tax assets as of December 31, 2014 and 2013, respectively. See Note 1 under "Recently Issued Accounting Standards" for additional information. |
Financial data for products and services | Products and Services Electric Utilities' Revenues Year Retail Wholesale Other Total (in millions) 2015 $ 14,987 $ 1,798 $ 657 $ 17,442 2014 15,550 2,184 672 18,406 2013 14,541 1,855 639 17,035 |
Noncontrolling Interest (Tables
Noncontrolling Interest (Tables) - Southern Power [Member] | 12 Months Ended |
Dec. 31, 2015 | |
Noncontrolling Interest [Line Items] | |
Redeemable Noncontrolling Interest | The following table details the components of redeemable noncontrolling interests for the years ended December 31: 2015 2014 2013 (in millions) Beginning balance $ 39 $ 29 $ 8 Net income attributable to redeemable noncontrolling interests 2 4 4 Distributions to redeemable noncontrolling interests — (1 ) — Capital contributions from redeemable noncontrolling interests 2 7 17 Ending balance $ 43 $ 39 $ 29 |
Condensed Income Statement | For the years ended December 31, 2015 and 2014, net income included in the consolidated statements of changes in stockholders' equity is reconciled to net income presented in the consolidated statements of income as follows: 2015 2014 (in millions) Net income attributable to the Company $ 215 $ 172 Net income (loss) attributable to noncontrolling interests 12 (1 ) Net income attributable to redeemable noncontrolling interests 2 4 Net income $ 229 $ 175 |
Quarterly Financial Informati43
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2015 and 2014 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 2015 $ 4,183 $ 957 $ 508 $ 0.56 $ 0.56 $ 0.5250 $ 53.16 $ 43.55 June 2015 4,337 1,098 629 0.69 0.69 0.5425 45.44 41.40 September 2015 5,401 1,649 959 1.05 1.05 0.5425 46.84 41.81 December 2015 3,568 578 271 0.30 0.30 0.5425 47.50 43.38 March 2014 $ 4,644 $ 700 $ 351 $ 0.39 $ 0.39 $ 0.5075 $ 44.00 $ 40.27 June 2014 4,467 1,103 611 0.68 0.68 0.5250 46.81 42.55 September 2014 5,339 1,278 718 0.80 0.80 0.5250 45.47 41.87 December 2014 4,017 561 283 0.31 0.31 0.5250 51.28 43.55 |
Alabama Power [Member] | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2015 $ 1,401 $ 346 $ 169 June 2015 1,455 398 200 September 2015 1,695 555 295 December 2015 1,217 264 121 March 2014 $ 1,508 $ 381 $ 187 June 2014 1,437 357 173 September 2014 1,669 520 282 December 2014 1,328 267 119 |
Georgia Power [Member] | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2015 $ 1,978 $ 454 $ 236 June 2015 2,016 554 277 September 2015 2,691 964 551 December 2015 1,641 376 196 March 2014 $ 2,269 $ 516 $ 266 June 2014 2,186 572 311 September 2014 2,631 920 525 December 2014 1,902 288 123 |
Gulf Power [Member] | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in millions) March 2015 $ 357 $ 72 $ 37 June 2015 384 69 35 September 2015 429 91 48 December 2015 313 58 28 March 2014 $ 407 $ 74 $ 37 June 2014 384 69 34 September 2014 438 88 46 December 2014 361 50 23 |
Mississippi Power [Member] | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) After Dividends on Preferred Stock (in millions) March 2015 $ 276 $ 24 $ 35 June 2015 275 12 49 September 2015 341 (66 ) (21 ) December 2015 246 (143 ) (71 ) March 2014 $ 331 $ (325 ) $ (172 ) June 2014 311 56 62 September 2014 355 (349 ) (195 ) December 2014 246 (71 ) (24 ) |
Southern Power [Member] | |
Quarterly Financial Information [Line Items] | |
Summarized quarterly financial data | Summarized quarterly financial information for 2015 and 2014 is as follows: Quarter Ended Operating Revenues Operating Income Net Income Attributable to the Company (in millions) March 2015 $ 348 $ 67 $ 33 June 2015 337 75 46 September 2015 401 129 102 December 2015 304 55 34 March 2014 $ 351 $ 59 $ 33 June 2014 329 51 31 September 2014 435 105 64 December 2014 386 40 44 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | Jan. 01, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 5,564 | $ 4,664 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||
Other cost of removal obligations [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ (1,177) | (1,229) | |
Over recovered regulatory clause revenues [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (261) | (48) | |
Deferred income tax credits [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (187) | (192) | |
Property damage reserves-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (178) | (181) | |
Asset retirement obligations-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (45) | (130) | |
Other regulatory liabilities [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (35) | (47) | |
Kemper regulatory liability (Mirror CWIP) [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 0 | (271) | |
Retiree benefit plans [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 3,440 | 3,469 | |
Deferred income tax charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 1,514 | 1,458 | |
Asset retirement obligations-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 481 | 119 | |
Other regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 299 | 275 | |
Loss on reacquired debt [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 248 | 267 | |
Fuel hedging-asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 225 | 202 | |
Kemper IGCC regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 216 | 148 | |
Vacation pay [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 178 | 177 | |
Deferred PPA charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 163 | 185 | |
Under recovered regulatory clause revenues [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 142 | 157 | |
Remaining net book value of retired units [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 283 | 44 | |
Environmental remediation-asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 78 | 64 | |
Property damage reserves - asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 92 | 98 | |
Nuclear outage [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 88 | 99 | |
Maximum [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 15 years | ||
Life of New Issue | 50 years | ||
Fuel Hedging Assets and Liabilities, Amortization Period | 5 years | ||
Power Purchase Agreement Period | 8 years | ||
Recovered and Amortized as Approved by Appropriate State PSCs | 11 years | ||
Amortization Period For Other Regulatory Liabilities | 15 years | ||
Maximum [Member] | Other regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization Period For Other Regulatory Assets | 15 years | ||
Maximum [Member] | Property damage reserves - asset [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization Period For Other Regulatory Assets | 6 years | ||
Maximum [Member] | Asset Group 1 [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization Period For Other Regulatory Assets | 10 years | ||
Gulf Power [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 296 | 319 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Life of New Issue | 40 years | ||
Fuel Hedging Assets and Liabilities, Amortization Period | 5 years | ||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||
Recovered and Amortized as Approved by Appropriate State PSCs | 1 year | ||
Gulf Power [Member] | Other cost of removal obligations [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ (262) | (243) | |
Gulf Power [Member] | Over recovered regulatory clause revenues [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (22) | 0 | |
Gulf Power [Member] | Deferred income tax credits [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (3) | (4) | |
Gulf Power [Member] | Property damage reserves-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (38) | (35) | |
Gulf Power [Member] | Asset retirement obligations-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (1) | (5) | |
Gulf Power [Member] | Retiree benefit plans [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 147 | 148 | |
Gulf Power [Member] | Deferred income tax charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 59 | 53 | |
Gulf Power [Member] | Other regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 7 | 9 | |
Gulf Power [Member] | Loss on reacquired debt [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 15 | 16 | |
Gulf Power [Member] | Fuel hedging-asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 104 | 73 | |
Gulf Power [Member] | Vacation pay [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 10 | 10 | |
Gulf Power [Member] | Deferred return on transmission upgrades [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 10 | 0 | |
Gulf Power [Member] | Deferred PPA charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 163 | 185 | |
Gulf Power [Member] | Under recovered regulatory clause revenues [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 1 | 53 | |
Gulf Power [Member] | Environmental remediation-asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 46 | 48 | |
Gulf Power [Member] | Deferred income tax charges - Medicare subsidy [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 2 | 3 | |
Gulf Power [Member] | Regulatory Cost of Removal Credit [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 29 | 8 | |
Gulf Power [Member] | Ash Pond Closure [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 29 | 0 | |
Gulf Power [Member] | Maximum [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | ||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 65 years | ||
Recovered and Amortized as Approved by Appropriate State PSCs | 14 years | ||
Recovered and Amortization Periods as Approved by Appropriate State Public Service Commission | 8 years | ||
Gulf Power [Member] | Maximum [Member] | Generation Site Selection Evaluation Costs [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovered and Amortized as Approved by Appropriate State PSCs | 8 years | ||
Alabama Power [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 791 | 738 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Fuel Hedging Assets and Liabilities, Amortization Period | 3 years 6 months | ||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||
Medicare Drug Subsidy Obligation Related To Subsidiary | $ 17 | 18 | |
Amortization Period for Regulatory Deferrals | 11 years | ||
Alabama Power [Member] | Other cost of removal obligations [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ (722) | (744) | |
Alabama Power [Member] | Deferred income tax credits [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (70) | (72) | |
Alabama Power [Member] | Asset retirement obligations-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (40) | (125) | |
Alabama Power [Member] | Other regulatory liabilities [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (8) | (17) | |
Alabama Power [Member] | Nuclear disaster reserve [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (75) | (84) | |
Alabama Power [Member] | Retiree benefit plans [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 903 | 882 | |
Alabama Power [Member] | Deferred income tax charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 522 | 525 | |
Alabama Power [Member] | Other regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 53 | 49 | |
Alabama Power [Member] | Loss on reacquired debt [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 75 | 80 | |
Alabama Power [Member] | Fuel hedging-asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 55 | 53 | |
Alabama Power [Member] | Vacation pay [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 66 | 65 | |
Alabama Power [Member] | Under recovered regulatory clause revenues [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (97) | 57 | |
Alabama Power [Member] | Nuclear outage [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 53 | 56 | |
Alabama Power [Member] | Regulatory deferrals [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 76 | 13 | |
Alabama Power [Member] | Maximum [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 15 years | ||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 50 years | ||
Life of New Issue | 50 years | ||
Recovered and Amortized as Approved by Appropriate State PSCs | 15 years | ||
Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs | 10 years | ||
Georgia Power [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 2,933 | 2,529 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | ||
Other Cost of Removal Obligations Related to Subsidiary | $ 14 | ||
Amortization Period of Other Cost of Removal Obligations | 12 months | ||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||
Refueling Cycles Maximum Period | 24 months | ||
Period for Environmental Construction | 9 years | 9 years | |
Georgia Power [Member] | Other cost of removal obligations [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ (31) | (60) | |
Georgia Power [Member] | Deferred income tax credits [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (105) | (106) | |
Georgia Power [Member] | Other regulatory liabilities [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (2) | (7) | |
Georgia Power [Member] | Retiree benefit plans [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 1,307 | 1,325 | |
Georgia Power [Member] | Deferred income tax charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 653 | 668 | |
Georgia Power [Member] | Asset retirement obligations-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 411 | 108 | |
Georgia Power [Member] | Other regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 140 | 153 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovered and Amortized as Approved by Appropriate State PSCs | 12 years | ||
Georgia Power [Member] | Loss on reacquired debt [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 150 | 163 | |
Georgia Power [Member] | Vacation pay [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 91 | 91 | |
Georgia Power [Member] | Remaining net book value of retired units [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 171 | 29 | |
Georgia Power [Member] | Canceled construction projects [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 56 | 67 | |
Georgia Power [Member] | Deferred income tax charges - Medicare subsidy [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovered and Amortized as Approved by Appropriate State PSCs | 6 years | ||
Georgia Power [Member] | Storm Reserve [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 92 | 98 | |
Georgia Power [Member] | Maximum [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 70 years | ||
Life of New Issue | 38 years | ||
Recovered and Amortized as Approved by Appropriate State PSCs | 10 years | ||
Mississippi Power [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 667 | 172 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | ||
Fuel Hedging Assets and Liabilities, Amortization Period | 3 years | ||
Mississippi Power [Member] | Other cost of removal obligations [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ (167) | (166) | |
Mississippi Power [Member] | Property damage reserves-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (64) | (62) | |
Mississippi Power [Member] | Other regulatory liabilities [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | (11) | (13) | |
Mississippi Power [Member] | Deferred income tax charges [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 291 | 227 | |
Mississippi Power [Member] | Asset retirement obligations-liability [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 70 | 11 | |
Mississippi Power [Member] | Other regulatory assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 16 | 18 | |
Mississippi Power [Member] | Fuel hedging-asset [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 50 | 47 | |
Mississippi Power [Member] | Vacation pay [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 11 | 11 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||
Mississippi Power [Member] | Remaining net book value of retired units [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 36 | 2 | |
Mississippi Power [Member] | Mirror Construction Work In Progress [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 0 | (271) | |
Mississippi Power [Member] | Kemper IGCC [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | 216 | 148 | |
Mississippi Power [Member] | Property tax [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 27 | 28 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization Period of Regulatory Assets and Liabilities | 12 months | ||
Mississippi Power [Member] | Retiree Benefit Plans - Regulatory Assets [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 163 | 169 | |
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Total assets (liabilities), net | $ 29 | $ 23 | |
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs | 10 years | ||
Regulatory Assets Associated with Asset Retirement Obligations [Member] | Mississippi Power [Member] | |||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | |||
Amortization Period of Regulatory Assets and Liabilities | 49 years |
Summary of Significant Accoun45
Summary of Significant Accounting Policies - Property, Plant, and Equipment (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | $ 41,648 | $ 37,892 |
Transmission | 10,544 | 9,884 |
Distribution | 17,670 | 17,123 |
General | 4,377 | 4,198 |
Plant acquisition adjustment | 123 | 123 |
Utility plant in service | 74,362 | 69,220 |
Information technology equipment and software | 222 | 244 |
Communications equipment | 418 | 439 |
Other | 116 | 110 |
Other plant in service | 756 | 793 |
Total plant in service | 75,118 | 70,013 |
Alabama Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 12,820 | 11,670 |
Transmission | 3,773 | 3,579 |
Distribution | 6,432 | 6,196 |
General | 1,713 | 1,623 |
Plant acquisition adjustment | 12 | 12 |
Total plant in service | 24,750 | 23,080 |
Georgia Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 15,386 | 15,201 |
Transmission | 5,355 | 5,086 |
Distribution | 9,151 | 8,913 |
General | 1,921 | 1,855 |
Plant acquisition adjustment | 28 | 28 |
Total plant in service | 31,841 | 31,083 |
Gulf Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 2,974 | 2,638 |
Transmission | 691 | 516 |
Distribution | 1,196 | 1,157 |
General | 182 | 182 |
Plant acquisition adjustment | 2 | 2 |
Total plant in service | 5,045 | 4,495 |
Mississippi Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 2,723 | 2,293 |
Transmission | 688 | 665 |
Distribution | 891 | 854 |
General | 503 | 485 |
Plant acquisition adjustment | 81 | 81 |
Total plant in service | $ 4,886 | $ 4,378 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Capital Leased Assets (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Accumulated Amortization | $ (59) | $ (49) |
Capital Leased Assets, Net of Amortization | 152 | 161 |
Office Building [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | 61 | 61 |
Nitrogen Plant [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | 83 | 83 |
Computer-Related Equipment [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | 61 | 60 |
Gas Pipeline [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | $ 6 | $ 6 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | $ 2,201 | $ 2,018 |
Liabilities incurred | 662 | 18 |
Liabilities settled | (37) | (17) |
Accretion | 115 | 102 |
Cash flow revisions | 818 | 80 |
Balance at end of year | 3,759 | 2,201 |
Alabama Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 829 | 730 |
Liabilities incurred | 402 | 1 |
Liabilities settled | (3) | (3) |
Accretion | 53 | 45 |
Cash flow revisions | 167 | 56 |
Balance at end of year | 1,448 | 829 |
Georgia Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 1,255 | 1,222 |
Liabilities incurred | 6 | 9 |
Liabilities settled | (30) | (12) |
Accretion | 56 | 53 |
Cash flow revisions | 629 | (17) |
Balance at end of year | 1,916 | 1,255 |
Gulf Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 17 | 16 |
Liabilities incurred | 105 | 0 |
Liabilities settled | (1) | 0 |
Accretion | 2 | 1 |
Cash flow revisions | 7 | 0 |
Balance at end of year | 130 | 17 |
Mississippi Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 48 | 42 |
Liabilities incurred | 101 | 0 |
Liabilities settled | (3) | (3) |
Accretion | 4 | 2 |
Cash flow revisions | 27 | 7 |
Balance at end of year | 177 | 48 |
Southern Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 13 | 4 |
Liabilities incurred | 7 | 8 |
Accretion | 1 | 1 |
Balance at end of year | $ 21 | $ 13 |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Intangible Assets (Details) - Southern Power [Member] $ in Millions | Dec. 31, 2015USD ($) |
Acquired Finite-Lived Intangible Assets [Line Items] | |
2,016 | $ 10 |
2,017 | 17 |
2,018 | 17 |
2,019 | 17 |
2,020 | 17 |
2021 and beyond | 239 |
Total | $ 317 |
Summary of Significant Accoun49
Summary of Significant Accounting Policies - Accumulated Provisions and Estimated Costs For Decommissioning (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Alabama Power [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | $ 754 | $ 775 |
Decommissioning | ||
Total site study costs | $ 1,442 | |
Alabama Power [Member] | Plant Farley [Member] | ||
Decommissioning | ||
Beginning Year | 2,037 | |
Completion Year | 2,076 | |
Alabama Power [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | $ 734 | 754 |
Alabama Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 20 | 21 |
Alabama Power [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 1,362 | |
Alabama Power [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | $ 80 | |
Plant Farley [Member] | ||
Decommissioning | ||
Beginning Year | 2,037 | |
Completion Year | 2,076 | |
Total site study costs | $ 1,442 | |
Plant Farley [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 1,362 | |
Plant Farley [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 0 | |
Plant Farley [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 80 | |
Plant Farley [Member] | Alabama Power [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 754 | 775 |
Plant Farley [Member] | Alabama Power [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 734 | 754 |
Plant Farley [Member] | Alabama Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | $ 20 | 21 |
Plant Hatch [Member] | ||
Decommissioning | ||
Beginning Year | 2,034 | |
Completion Year | 2,075 | |
Total site study costs | $ 902 | |
Plant Hatch [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 678 | |
Plant Hatch [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 160 | |
Plant Hatch [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 64 | |
Plant Hatch [Member] | Georgia Power [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | $ 487 | 496 |
Decommissioning | ||
Beginning Year | 2,034 | |
Completion Year | 2,075 | |
Total site study costs | $ 902 | |
Plant Hatch [Member] | Georgia Power [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 487 | 496 |
Plant Hatch [Member] | Georgia Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 0 | 0 |
Plant Hatch [Member] | Georgia Power [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 678 | |
Plant Hatch [Member] | Georgia Power [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 160 | |
Plant Hatch [Member] | Georgia Power [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | $ 64 | |
Plant Vogtle Units 1 and 2 [Member] | ||
Decommissioning | ||
Beginning Year | 2,047 | |
Completion Year | 2,079 | |
Total site study costs | $ 804 | |
Plant Vogtle Units 1 and 2 [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 568 | |
Plant Vogtle Units 1 and 2 [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 147 | |
Plant Vogtle Units 1 and 2 [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 89 | |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | $ 288 | 293 |
Decommissioning | ||
Beginning Year | 2,047 | |
Completion Year | 2,079 | |
Total site study costs | $ 804 | |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 288 | 293 |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Accumulated Provisions for Decommissioning | 0 | $ 0 |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 568 | |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 147 | |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | $ 89 |
Summary of Significant Accoun50
Summary of Significant Accounting Policies - Leveraged Leases (Details) - Domestic And International Leveraged Lease [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net Investments from Leveraged Lease | |||
Net rentals receivable | $ 1,487 | $ 1,495 | |
Unearned income | (732) | (752) | |
Investment in leveraged leases | 755 | 743 | |
Deferred taxes from leveraged leases | (303) | (299) | |
Net investment in leveraged leases | 452 | 444 | |
Components of Income from Leveraged Lease | |||
Pretax leveraged lease income (loss) | 20 | 24 | $ (5) |
Income tax expense | (7) | (9) | 2 |
Net leveraged lease income (loss) | $ 13 | $ 15 | $ (3) |
Summary of Significant Accoun51
Summary of Significant Accounting Policies - Accumulated OCI (loss) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | $ (128) | ||
Current period change | (2) | $ (53) | $ 48 |
Ending Balance | (130) | (128) | |
Qualifying Hedges [Member] | |||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | (41) | ||
Current period change | (7) | ||
Ending Balance | (48) | (41) | |
Marketable Securities [Member] | |||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | 0 | ||
Current period change | 0 | ||
Ending Balance | 0 | 0 | |
Pension and Other Postretirement Benefit Plans [Member] | |||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | (87) | ||
Current period change | 5 | ||
Ending Balance | $ (82) | $ (87) |
Summary of Significant Accoun52
Summary of Significant Accounting Policies - Customer Revenues (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 10.00% | ||
Customer Concentration Risk [Member] | Southern Power [Member] | Georgia Power [Member] | Sales Revenue, Goods, Net [Member] | |||
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 15.80% | 10.10% | 11.80% |
Customer Concentration Risk [Member] | Southern Power [Member] | Florida Power and Light [Member] | Sales Revenue, Goods, Net [Member] | |||
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 10.70% | 9.70% | 10.70% |
Customer Concentration Risk [Member] | Southern Power [Member] | Duke Energy Corporation [Member] | Sales Revenue, Goods, Net [Member] | |||
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 8.20% | 9.10% | 10.30% |
Summary of Significant Accoun53
Summary of Significant Accounting Policies - Textual (Details) | Feb. 06, 2015MW | Dec. 31, 2013USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)kWhProperty | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Oct. 06, 2015USD ($) | Dec. 31, 2010USD ($) |
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | $ 2,018,000,000 | $ 2,201,000,000 | $ 3,759,000,000 | $ 2,201,000,000 | $ 3,759,000,000 | $ 2,201,000,000 | $ 2,018,000,000 | |||||||||
Retail Revenues | 14,987,000,000 | 15,550,000,000 | 14,541,000,000 | |||||||||||||
Net income after dividends on preferred and preference stock | 271,000,000 | $ 959,000,000 | $ 629,000,000 | $ 508,000,000 | 283,000,000 | $ 718,000,000 | $ 611,000,000 | $ 351,000,000 | 2,367,000,000 | 1,963,000,000 | 1,644,000,000 | |||||
Unamortized Debt Issuance Expense | (139,000,000) | (202,000,000) | (241,000,000) | (202,000,000) | $ (241,000,000) | (202,000,000) | (139,000,000) | |||||||||
Maximum revenue from a single customer or industry | 10.00% | |||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | |||||||||||||||
Deferred tax assets | 5,241,000,000 | 6,358,000,000 | 5,241,000,000 | $ 6,358,000,000 | 5,241,000,000 | |||||||||||
Non-cash property additions recognized | 844,000,000 | 528,000,000 | 411,000,000 | |||||||||||||
Other Cost of Removal Obligations | 1,215,000,000 | 1,162,000,000 | 1,215,000,000 | 1,162,000,000 | 1,215,000,000 | |||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 24,059,000,000 | 24,253,000,000 | 24,059,000,000 | 24,253,000,000 | 24,059,000,000 | |||||||||||
Investment securities in the Funds | 1,546,000,000 | 1,512,000,000 | 1,546,000,000 | 1,512,000,000 | 1,546,000,000 | |||||||||||
Proceeds from sale of securities held in external trust funds | 1,400,000,000 | 913,000,000 | 1,000,000,000 | |||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 11,000,000 | $ 98,000,000 | $ 181,000,000 | |||||||||||||
AFUDC, net of income taxes | 12.80% | 16.00% | 15.00% | |||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | $ 226,000,000 | $ 245,000,000 | $ 190,000,000 | |||||||||||||
Cash payments for interest totaled | 809,000,000 | 732,000,000 | 759,000,000 | |||||||||||||
Net of amounts capitalized | 124,000,000 | 111,000,000 | 92,000,000 | |||||||||||||
Other Regulatory Assets Current | 346,000,000 | 402,000,000 | 346,000,000 | 402,000,000 | 346,000,000 | |||||||||||
Other Regulatory Assets Deferred | 4,334,000,000 | 4,989,000,000 | 4,334,000,000 | $ 4,989,000,000 | 4,334,000,000 | |||||||||||
Original Maturities of Temporary Cash Investments | 90 days | |||||||||||||||
Plant acquisition adjustment | 123,000,000 | 123,000,000 | 123,000,000 | $ 123,000,000 | 123,000,000 | |||||||||||
Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Leveraged lease agreement term | 45 years | |||||||||||||||
Plant Hatch [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Estimated cost of decommissioning completion year | 2,075 | |||||||||||||||
Equity Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 886,000,000 | 817,000,000 | 886,000,000 | $ 817,000,000 | 886,000,000 | |||||||||||
Debt Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 638,000,000 | 654,000,000 | 638,000,000 | 654,000,000 | 638,000,000 | |||||||||||
Other Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 19,000,000 | 38,000,000 | 19,000,000 | 38,000,000 | 19,000,000 | |||||||||||
Securities Held in Funds [Member] | Unrealized Loss [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 83,000,000 | |||||||||||||||
Securities Held in Funds [Member] | Unrealized Gain [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 19,000,000 | $ 119,000,000 | ||||||||||||||
Utility Plant in Service [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.00% | 3.10% | 3.30% | |||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 23,500,000,000 | 23,700,000,000 | 23,500,000,000 | $ 23,700,000,000 | $ 23,500,000,000 | |||||||||||
Other Plant in Service [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 533,000,000 | 510,000,000 | 533,000,000 | $ 510,000,000 | 533,000,000 | |||||||||||
Other Plant in Service [Member] | Minimum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Plant in service, estimated useful lives | 3 years | |||||||||||||||
Other Plant in Service [Member] | Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Plant in service, estimated useful lives | 25 years | |||||||||||||||
Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 488,000,000 | $ 143,000,000 | ||||||||||||||
Alabama Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | $ 730,000,000 | 829,000,000 | 1,448,000,000 | 829,000,000 | $ 1,448,000,000 | 829,000,000 | 730,000,000 | |||||||||
Retail Revenues | 5,234,000,000 | 5,249,000,000 | 4,952,000,000 | |||||||||||||
Net income after dividends on preferred and preference stock | 121,000,000 | 295,000,000 | 200,000,000 | 169,000,000 | 119,000,000 | 282,000,000 | 173,000,000 | 187,000,000 | 785,000,000 | 761,000,000 | 712,000,000 | |||||
Unamortized Debt Issuance Expense | (39,000,000) | (45,000,000) | (39,000,000) | $ (45,000,000) | (39,000,000) | |||||||||||
Maximum revenue from a single customer or industry | 10.00% | |||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | |||||||||||||||
Deferred tax assets | 1,141,000,000 | 1,511,000,000 | 1,141,000,000 | $ 1,511,000,000 | 1,141,000,000 | |||||||||||
Number of Units for which Outage Operations and Maintenance Expenses Accrued | Property | 2 | |||||||||||||||
Period Over which Deferred Costs are Being Amortized to Nuclear Operations and Maintenance Expenses | 18 months | |||||||||||||||
Other Cost of Removal Obligations | 744,000,000 | 722,000,000 | 744,000,000 | $ 722,000,000 | 744,000,000 | |||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 8,522,000,000 | 8,736,000,000 | 8,522,000,000 | 8,736,000,000 | 8,522,000,000 | |||||||||||
Regulatory liabilities amortized | 120,000,000 | |||||||||||||||
Decommissioning Fund Investments Net Of Foreign Currency | 754,000,000 | 734,000,000 | 754,000,000 | 734,000,000 | 754,000,000 | |||||||||||
Investment securities in the Funds | $ 756,000,000 | $ 737,000,000 | $ 756,000,000 | 737,000,000 | 756,000,000 | |||||||||||
Proceeds from sale of securities held in external trust funds | 438,000,000 | 244,000,000 | 279,000,000 | |||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 8,000,000 | $ 54,000,000 | $ 120,000,000 | |||||||||||||
Significant assumption of inflation rate used to determine the costs for rate making | 4.50% | |||||||||||||||
Significant assumption of trust earnings rate used to determine the costs for rate making | 7.00% | |||||||||||||||
Composite rate used to determine allowance for funds used during construction | 9.10% | 8.80% | 8.70% | 8.80% | 8.70% | 8.80% | 9.10% | |||||||||
AFUDC, net of income taxes | 9.30% | 7.90% | 5.40% | |||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | $ 60,000,000 | $ 49,000,000 | $ 32,000,000 | |||||||||||||
Cash payments for interest totaled | 250,000,000 | 231,000,000 | 243,000,000 | |||||||||||||
Net of amounts capitalized | 22,000,000 | 18,000,000 | 11,000,000 | |||||||||||||
Other Regulatory Assets Current | $ 84,000,000 | $ 115,000,000 | $ 84,000,000 | 115,000,000 | 84,000,000 | |||||||||||
Other Regulatory Assets Deferred | 1,063,000,000 | 1,114,000,000 | 1,063,000,000 | $ 1,114,000,000 | 1,063,000,000 | |||||||||||
Original Maturities of Temporary Cash Investments | 90 days | |||||||||||||||
Plant acquisition adjustment | 12,000,000 | 12,000,000 | 12,000,000 | $ 12,000,000 | 12,000,000 | |||||||||||
Alabama Power [Member] | Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 50 years | |||||||||||||||
Alabama Power [Member] | Equity Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 583,000,000 | 521,000,000 | 583,000,000 | $ 521,000,000 | 583,000,000 | |||||||||||
Alabama Power [Member] | Debt Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 163,000,000 | 191,000,000 | 163,000,000 | 191,000,000 | 163,000,000 | |||||||||||
Alabama Power [Member] | Other Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 8,000,000 | 22,000,000 | 8,000,000 | 22,000,000 | 8,000,000 | |||||||||||
Alabama Power [Member] | Securities Held in Funds [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 19,000,000 | $ 85,000,000 | ||||||||||||||
Alabama Power [Member] | Securities Held in Funds [Member] | Unrealized Gain [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 57,000,000 | |||||||||||||||
Alabama Power [Member] | Utility Plant in Service [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.90% | 3.30% | 3.20% | |||||||||||||
Alabama Power [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 438,000,000 | $ 400,000,000 | $ 340,000,000 | |||||||||||||
Alabama Power [Member] | Southern Nuclear Operating Company, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 243,000,000 | 234,000,000 | 211,000,000 | |||||||||||||
Alabama Power [Member] | Gulf Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Revenue Requirements Reimbursement | $ 14,000,000 | |||||||||||||||
Alabama Power [Member] | Plant Farley [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Estimated cost of decommissioning completion year | 2,076 | |||||||||||||||
Alabama Power [Member] | Fuel Purchases [Member] | Mississippi Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 8,000,000 | 34,000,000 | 27,000,000 | |||||||||||||
Alabama Power [Member] | Non-Fuel Expense [Member] | Mississippi Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 11,000,000 | 13,000,000 | 13,000,000 | |||||||||||||
Mississippi Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | $ 42,000,000 | 48,000,000 | 177,000,000 | 48,000,000 | 177,000,000 | 48,000,000 | 42,000,000 | |||||||||
Retail Revenues | 776,000,000 | 795,000,000 | 799,000,000 | |||||||||||||
Net income after dividends on preferred and preference stock | (71,000,000) | (21,000,000) | 49,000,000 | 35,000,000 | (24,000,000) | (195,000,000) | 62,000,000 | (172,000,000) | (8,000,000) | (329,000,000) | $ (477,000,000) | |||||
Unamortized Debt Issuance Expense | (9,000,000) | (8,000,000) | (9,000,000) | $ (8,000,000) | (9,000,000) | |||||||||||
Percentage Of Wholesale Customers To Operating Revenue | 21.00% | |||||||||||||||
Period Of Contract Cancellation Notices Of Wholesale Customers | 10 years | |||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | |||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | |||||||||||||||
Deferred tax assets | 1,251,000,000 | 1,400,000,000 | 1,251,000,000 | $ 1,400,000,000 | $ 1,251,000,000 | |||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 4.70% | 3.30% | 3.40% | |||||||||||||
Other Cost of Removal Obligations | 166,000,000 | 165,000,000 | 166,000,000 | $ 165,000,000 | $ 166,000,000 | |||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 1,173,000,000 | $ 1,262,000,000 | $ 1,173,000,000 | $ 1,262,000,000 | $ 1,173,000,000 | |||||||||||
Composite rate used to determine allowance for funds used during construction | 6.89% | 6.91% | 5.99% | 6.91% | 5.99% | 6.91% | 6.89% | |||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | $ 110,000,000 | $ 136,000,000 | $ 122,000,000 | |||||||||||||
Threshold above which actual damages are charged to the reserve | $ 50,000 | 50,000 | ||||||||||||||
Retail accrual per annual SRR rate | $ 3,000,000 | $ 3,000,000 | 3,000,000 | $ 3,000,000 | 3,000,000 | 3,000,000 | 3,000,000 | |||||||||
Wholesale accrual per annual SRR rate | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | |||||||||
Cash payments for interest totaled | 45,000,000 | 7,000,000 | 20,000,000 | |||||||||||||
Net of amounts capitalized | 66,000,000 | 69,000,000 | 54,000,000 | |||||||||||||
PSC Approved Annual Property Damage Reserve Accrual | $ 3,000,000 | |||||||||||||||
Other Regulatory Assets Current | 73,000,000 | 95,000,000 | 73,000,000 | 95,000,000 | 73,000,000 | |||||||||||
Other Regulatory Assets Deferred | 385,000,000 | 525,000,000 | 385,000,000 | $ 525,000,000 | 385,000,000 | |||||||||||
Original Maturities of Temporary Cash Investments | 90 days | |||||||||||||||
Plant acquisition adjustment | 81,000,000 | 81,000,000 | 81,000,000 | $ 81,000,000 | 81,000,000 | |||||||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | |||||||||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | 23,000,000 | 24,000,000 | 25,000,000 | 24,000,000 | $ 25,000,000 | 24,000,000 | 23,000,000 | |||||||||
Mississippi Power [Member] | Mississippi Public Service Commission [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Period To Agree On System Restoration Rider | 3 years | |||||||||||||||
Mississippi Power [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 295,000,000 | 259,000,000 | 205,000,000 | |||||||||||||
Mississippi Power [Member] | Gulf Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 27,000,000 | 31,000,000 | 17,000,000 | |||||||||||||
Mississippi Power [Member] | Property tax [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Amortization period of regulatory assets and liabilities | 12 months | |||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | 11,000,000 | $ 11,000,000 | ||||||||||||||
Grants expected to be received from Department of Energy | 25,000,000 | 25,000,000 | $ 270,000,000 | |||||||||||||
Grants received from Department of Energy | 245,000,000 | |||||||||||||||
Regulatory asset | 120,000,000 | 120,000,000 | ||||||||||||||
Other Regulatory Assets Current | 96,000,000 | 96,000,000 | ||||||||||||||
Other Regulatory Assets Deferred | 195,000,000 | $ 195,000,000 | ||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Minimum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Amortization period of regulatory assets and liabilities | 2 years | |||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Amortization period of regulatory assets and liabilities | 10 years | |||||||||||||||
Mississippi Power [Member] | Fuel Purchases [Member] | Alabama Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 8,000,000 | 34,000,000 | 27,000,000 | |||||||||||||
Mississippi Power [Member] | Non-Fuel Expense [Member] | Alabama Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 11,000,000 | 13,000,000 | 13,000,000 | |||||||||||||
Georgia Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | $ 1,222,000,000 | 1,255,000,000 | 1,916,000,000 | 1,255,000,000 | 1,916,000,000 | 1,255,000,000 | 1,222,000,000 | |||||||||
Retail Revenues | 7,727,000,000 | 8,240,000,000 | 7,620,000,000 | |||||||||||||
Net income after dividends on preferred and preference stock | 196,000,000 | 551,000,000 | 277,000,000 | 236,000,000 | 123,000,000 | 525,000,000 | 311,000,000 | 266,000,000 | 1,260,000,000 | 1,225,000,000 | $ 1,174,000,000 | |||||
Unamortized Debt Issuance Expense | (124,000,000) | (118,000,000) | (124,000,000) | $ (118,000,000) | (124,000,000) | |||||||||||
Maximum revenue from a single customer or industry | 10.00% | |||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | |||||||||||||||
Deferred tax assets | 1,736,000,000 | 2,017,000,000 | 1,736,000,000 | $ 2,017,000,000 | $ 1,736,000,000 | |||||||||||
Refueling cycles for Alabama Power and Georgia Power, minimum months | 18 months | |||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, maximum months | 24 months | |||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.70% | 2.70% | 3.00% | |||||||||||||
Other Cost of Removal Obligations | 46,000,000 | 16,000,000 | 46,000,000 | $ 16,000,000 | $ 46,000,000 | |||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 11,222,000,000 | 10,903,000,000 | 11,222,000,000 | 10,903,000,000 | 11,222,000,000 | |||||||||||
Regulatory liabilities amortized | $ 14,000,000 | 14,000,000 | $ 31,000,000 | |||||||||||||
Asset Retirement Obligation, Period Of Update Cycle | 3 years | |||||||||||||||
Fair market value of fund's securities on loan under the Funds' managers' securities lending program | 51,000,000 | 76,000,000 | 51,000,000 | $ 76,000,000 | 51,000,000 | |||||||||||
Fair value of collateral received | 52,000,000 | 78,000,000 | 52,000,000 | 78,000,000 | 52,000,000 | |||||||||||
Decommissioning Fund Investments Net Of Foreign Currency | 789,000,000 | 775,000,000 | 789,000,000 | 775,000,000 | 789,000,000 | |||||||||||
Investment securities in the Funds | $ 789,000,000 | $ 775,000,000 | $ 789,000,000 | 775,000,000 | 789,000,000 | |||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | $ 3,000,000 | $ 44,000,000 | $ 61,000,000 | |||||||||||||
Significant assumption of inflation rate used to determine the costs for rate making | 2.40% | |||||||||||||||
Significant assumption of trust earnings rate used to determine the costs for rate making | 4.40% | |||||||||||||||
Composite rate used to determine allowance for funds used during construction | 5.30% | 5.60% | 6.50% | 5.60% | 6.50% | 5.60% | 5.30% | |||||||||
AFUDC capitalized | $ 56,000,000 | $ 62,000,000 | $ 44,000,000 | |||||||||||||
AFUDC, net of income taxes | 3.90% | 4.60% | 3.30% | |||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | $ 40,000,000 | $ 45,000,000 | $ 30,000,000 | |||||||||||||
Cash payments for interest totaled | 353,000,000 | 319,000,000 | 344,000,000 | |||||||||||||
Net of amounts capitalized | 16,000,000 | 18,000,000 | 14,000,000 | |||||||||||||
Accrual Under Alternate Rate Plan | 30,000,000 | |||||||||||||||
Other Regulatory Assets Current | $ 136,000,000 | $ 123,000,000 | $ 136,000,000 | 123,000,000 | 136,000,000 | |||||||||||
Other Regulatory Assets Deferred | 1,753,000,000 | 2,152,000,000 | 1,753,000,000 | 2,152,000,000 | 1,753,000,000 | |||||||||||
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation | 29,000,000 | $ 29,000,000 | ||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | |||||||||||||||
Amortization period of other cost of removal obligations | 12 months | |||||||||||||||
Plant acquisition adjustment | 28,000,000 | 28,000,000 | 28,000,000 | $ 28,000,000 | 28,000,000 | |||||||||||
Georgia Power [Member] | Unrealized Losses [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 34,000,000 | |||||||||||||||
Georgia Power [Member] | Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 70 years | |||||||||||||||
Georgia Power [Member] | Plant Hatch [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Amount expensed for rate making purpose | 4,000,000 | |||||||||||||||
Estimated cost of decommissioning completion year | 2,075 | |||||||||||||||
Georgia Power [Member] | Plant Vogtle [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Amount expensed for rate making purpose | 2,000,000 | |||||||||||||||
Georgia Power [Member] | Securities Investment [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | $ 705,000,000 | 669,000,000 | 980,000,000 | 669,000,000 | $ 980,000,000 | 669,000,000 | 705,000,000 | |||||||||
Georgia Power [Member] | Equity Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 303,000,000 | 296,000,000 | 303,000,000 | 296,000,000 | 303,000,000 | |||||||||||
Georgia Power [Member] | Debt Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 475,000,000 | 463,000,000 | 475,000,000 | 463,000,000 | 475,000,000 | |||||||||||
Georgia Power [Member] | Other Securities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Investment securities in the Funds | 11,000,000 | 16,000,000 | 11,000,000 | 16,000,000 | 11,000,000 | |||||||||||
Georgia Power [Member] | Securities Held in Funds [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 26,000,000 | 0 | ||||||||||||||
Georgia Power [Member] | Southern Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 179,000,000 | 144,000,000 | 136,000,000 | |||||||||||||
Prepaid capacity expenses | 15,000,000 | $ 15,000,000 | 15,000,000 | 15,000,000 | 15,000,000 | |||||||||||
Georgia Power [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 585,000,000 | 555,000,000 | 504,000,000 | |||||||||||||
Georgia Power [Member] | Southern Nuclear Operating Company, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 681,000,000 | 643,000,000 | 555,000,000 | |||||||||||||
Georgia Power [Member] | Gulf Power [Member] | Plant Scherer Unit 3 [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Gulf Power agreement, percentage reimbursement of non-fuel expenses | 25.00% | 25.00% | ||||||||||||||
Georgia Power [Member] | Other regulatory assets current [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Environmental Regulatory Assets | $ 2,000,000 | $ 2,000,000 | ||||||||||||||
Georgia Power [Member] | Other regulatory assets deferred [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Environmental Regulatory Assets | 30,000,000 | 30,000,000 | ||||||||||||||
Georgia Power [Member] | Property damage reserves-liability [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Regulatory asset | 98,000,000 | 92,000,000 | 98,000,000 | 92,000,000 | 98,000,000 | |||||||||||
Other Regulatory Assets Current | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | |||||||||||
Other Regulatory Assets Deferred | 68,000,000 | 62,000,000 | 68,000,000 | 62,000,000 | 68,000,000 | |||||||||||
Georgia Power [Member] | Non-Fuel Expense [Member] | Gulf Power [Member] | Plant Scherer Unit 3 [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Gulf Power agreement, reimbursement of non-fuel expenses | 12,000,000 | 9,000,000 | 10,000,000 | |||||||||||||
Southern Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | 4,000,000 | 13,000,000 | 21,000,000 | 13,000,000 | 21,000,000 | 13,000,000 | 4,000,000 | |||||||||
Net income after dividends on preferred and preference stock | 34,000,000 | 102,000,000 | 46,000,000 | 33,000,000 | 44,000,000 | 64,000,000 | 31,000,000 | 33,000,000 | ||||||||
Unamortized Debt Issuance Expense | (11,000,000) | (19,000,000) | (11,000,000) | (19,000,000) | (11,000,000) | |||||||||||
Deferred tax assets | 481,000,000 | 794,000,000 | 481,000,000 | $ 794,000,000 | 481,000,000 | |||||||||||
Reduction in tax basis of assets | 50.00% | |||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,035,000,000 | 1,248,000,000 | 1,035,000,000 | $ 1,248,000,000 | 1,035,000,000 | |||||||||||
Plant In Service Depreciated On A Units Of Production Basis | 470,000,000 | 485,000,000 | 470,000,000 | 485,000,000 | 470,000,000 | |||||||||||
Cash payments for interest totaled | 74,000,000 | 85,000,000 | 60,000,000 | |||||||||||||
Net of amounts capitalized | 14,000,000 | 0 | 9,000,000 | |||||||||||||
Restricted Cash and Cash Equivalents, Noncurrent | 5,000,000 | $ 5,000,000 | ||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | |||||||||||||||
Period Of Reimbursement Of Transmission Costs | 5 years | |||||||||||||||
Amortization of Intangible Assets | $ 3,000,000 | 3,000,000 | 3,000,000 | |||||||||||||
Average term of PPAs | 20 years | |||||||||||||||
Deferred project development costs | 11,000,000 | 11,000,000 | 11,000,000 | $ 11,000,000 | 11,000,000 | |||||||||||
Southern Power [Member] | Minimum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Plant in service, estimated useful lives | 30 years | |||||||||||||||
Southern Power [Member] | Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Plant in service, estimated useful lives | 45 years | |||||||||||||||
Southern Power [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 146,000,000 | 126,000,000 | 118,000,000 | |||||||||||||
Southern Power [Member] | Operations and Maintenance Expense [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 138,000,000 | 125,000,000 | 114,000,000 | |||||||||||||
Southern Power [Member] | Electric Transmission [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 11,000,000 | $ 7,000,000 | $ 8,000,000 | |||||||||||||
Southern Power [Member] | Florida Power and Light [Member] | Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Maximum revenue from a single customer or industry | 10.70% | 9.70% | 10.70% | |||||||||||||
Southern Power [Member] | Georgia Power [Member] | Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Maximum revenue from a single customer or industry | 15.80% | 10.10% | 11.80% | |||||||||||||
Southern Power [Member] | Purchased Power from Affiliates [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 219,000,000 | $ 153,000,000 | $ 150,000,000 | |||||||||||||
Southern Power [Member] | Operating Lease PPA [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 109,000,000 | 75,000,000 | 69,000,000 | |||||||||||||
Gulf Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | $ 16,000,000 | 17,000,000 | 130,000,000 | 17,000,000 | 130,000,000 | 17,000,000 | 16,000,000 | |||||||||
Retail Revenues | 1,249,000,000 | 1,267,000,000 | 1,170,000,000 | |||||||||||||
Net income after dividends on preferred and preference stock | 28,000,000 | $ 48,000,000 | 35,000,000 | $ 37,000,000 | 23,000,000 | $ 46,000,000 | $ 34,000,000 | $ 37,000,000 | 148,000,000 | 140,000,000 | $ 124,000,000 | |||||
Unamortized Debt Issuance Expense | (8,000,000) | (8,000,000) | (8,000,000) | $ (8,000,000) | (8,000,000) | |||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | |||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | |||||||||||||||
Deferred tax assets | 171,000,000 | 216,000,000 | 171,000,000 | $ 216,000,000 | $ 171,000,000 | |||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.50% | 3.60% | 3.60% | |||||||||||||
Other Cost of Removal Obligations | 235,000,000 | 233,000,000 | 235,000,000 | $ 233,000,000 | $ 235,000,000 | |||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 1,296,000,000 | $ 1,296,000,000 | $ 1,296,000,000 | $ 1,296,000,000 | $ 1,296,000,000 | |||||||||||
Composite rate used to determine allowance for funds used during construction | 6.26% | 5.73% | 5.73% | 5.73% | 5.73% | 5.73% | 6.26% | |||||||||
AFUDC, net of income taxes | 10.80% | 10.93% | 6.87% | |||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | $ 13,000,000 | $ 12,000,000 | $ 6,000,000 | |||||||||||||
Cash payments for interest totaled | 52,000,000 | 48,000,000 | 53,000,000 | |||||||||||||
Net of amounts capitalized | 6,000,000 | 5,000,000 | 3,000,000 | |||||||||||||
PSC Approved Annual Property Damage Reserve Accrual | $ 3,500,000 | 3,500,000 | ||||||||||||||
Threshold above which additional property damage reserves are authorized by PSC | 3,500,000 | 3,500,000 | ||||||||||||||
Increase in accrued property damage costs | 3,500,000 | 3,500,000 | 3,500,000 | |||||||||||||
Accrued reserves | $ 35,000,000 | 38,000,000 | $ 35,000,000 | $ 38,000,000 | 35,000,000 | |||||||||||
Recovery Period For Natural Disaster Reserve Costs | 60 days | |||||||||||||||
Cumulative damage costs limit under PSC order | $ 100,000,000 | |||||||||||||||
PSC approved annual uninsured injuries and damages accrual | 1,600,000 | 1,600,000 | ||||||||||||||
Threshold above which additional uninsured injuries and damages accruals are authorized by PSC | 1,600,000 | 1,600,000 | ||||||||||||||
Reserve for losses and loss adjustment expenses | 4,000,000 | 0 | 4,000,000 | 0 | 4,000,000 | |||||||||||
Other Regulatory Assets Current | 74,000,000 | 90,000,000 | 74,000,000 | 90,000,000 | 74,000,000 | |||||||||||
Other Regulatory Assets Deferred | 416,000,000 | 427,000,000 | 416,000,000 | 427,000,000 | 416,000,000 | |||||||||||
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation | 46,000,000 | $ 46,000,000 | ||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | |||||||||||||||
Plant acquisition adjustment | 2,000,000 | 2,000,000 | 2,000,000 | $ 2,000,000 | 2,000,000 | |||||||||||
Net Regulatory Assets | 1,700,000 | $ 1,700,000 | ||||||||||||||
Gulf Power [Member] | Minimum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||||||||||
PSC approved target level for property damage reserve | 48,000,000 | $ 48,000,000 | ||||||||||||||
Gulf Power [Member] | Maximum [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
PSC approved target level for property damage reserve | 55,000,000 | 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 | $ 2,000,000 | ||||||||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 65 years | |||||||||||||||
Gulf Power [Member] | Georgia Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 12,000,000 | 9,000,000 | 10,000,000 | |||||||||||||
Gulf Power [Member] | Alabama Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Revenue Requirements Reimbursement | 14,000,000 | 12,000,000 | 8,000,000 | |||||||||||||
Gulf Power [Member] | Southern Company Services, Inc. [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 81,000,000 | 80,000,000 | 78,000,000 | |||||||||||||
Gulf Power [Member] | Mississippi Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Related Party Transaction, Amounts of Transaction | 27,000,000 | 31,000,000 | 17,000,000 | |||||||||||||
Gulf Power [Member] | Current Liabilities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Reserve for losses and loss adjustment expenses | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | |||||||||||
Gulf Power [Member] | Deferred Credits and Other Liabilities [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Reserve for losses and loss adjustment expenses | 2,400,000 | 100,000 | 2,400,000 | 100,000 | 2,400,000 | |||||||||||
Gulf Power [Member] | Plant Smith Units 1 and 2 [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Capacity Of Units Included In Request For Decertification Of Units | MW | 357 | |||||||||||||||
Net Book Value Of Planned Units Retirements | 62,000,000 | 62,000,000 | ||||||||||||||
Gulf Power [Member] | Plant Scholz [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Asset Retirement Obligation | 29,000,000 | $ 29,000,000 | ||||||||||||||
Alabama Power and Georgia Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, minimum months | 18 months | |||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, maximum months | 24 months | |||||||||||||||
Traditional Operating Companies [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Accrued reserves | $ 28,000,000 | $ 40,000,000 | 40,000,000 | $ 40,000,000 | $ 40,000,000 | 40,000,000 | 28,000,000 | |||||||||
Capital Lease Obligations [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Non-cash property additions recognized | 13,000,000 | 25,000,000 | $ 107,000,000 | |||||||||||||
Settlement Agreement [Member] | Gulf Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Other Cost of Removal Obligations | 62,500,000 | 62,500,000 | ||||||||||||||
Environmental Remediation Reserve [Member] | Georgia Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Costs recovered annually under rate plan | $ 2,000,000 | 3,000,000 | ||||||||||||||
Retail [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Proposed Property Damage Reserve | 63,000,000 | 63,000,000 | ||||||||||||||
Wholesale [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Proposed Property Damage Reserve | 1,000,000 | 1,000,000 | ||||||||||||||
Scenario, Plan [Member] | Alabama Power [Member] | Gulf Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Revenue Requirements Reimbursement | 12,000,000 | |||||||||||||||
Scenario, Plan [Member] | Gulf Power [Member] | Alabama Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Revenue Requirements Reimbursement | 12,000,000 | |||||||||||||||
Restatement Adjustment [Member] | Georgia Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Retail Revenues | (75,000,000) | |||||||||||||||
Net income after dividends on preferred and preference stock | $ (47,000,000) | |||||||||||||||
Investment Tax And Other Credit Carryforward [Member] | Georgia Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Deferred tax assets | $ 318,000,000 | $ 318,000,000 | ||||||||||||||
Deferred Charges Related To Income Taxes, Current [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 506,000,000 | |||||||||||||||
Deferred Charges Related To Income Taxes, Current [Member] | Other Noncurrent Assets [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 18,000,000 | |||||||||||||||
Deferred Charges Related To Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 488,000,000 | |||||||||||||||
Deferred Charges Related To Income Taxes, Current [Member] | Georgia Power [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 34,000,000 | |||||||||||||||
Prepaid Expense, Current [Member] | Alabama Power [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 20,000,000 | |||||||||||||||
Prepaid Expense, Current [Member] | Mississippi Power [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 121,000,000 | |||||||||||||||
Prepaid Expense, Current [Member] | Mississippi Power [Member] | Other Noncurrent Assets [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 16,000,000 | |||||||||||||||
Prepaid Expense, Current [Member] | Mississippi Power [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 105,000,000 | |||||||||||||||
Prepaid Expense, Current [Member] | Southern Power [Member] | Other Noncurrent Assets [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 306,000,000 | |||||||||||||||
Prepaid Expense, Current [Member] | Gulf Power [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 3,000,000 | |||||||||||||||
Accrued Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 2,000,000 | |||||||||||||||
Accrued Income Taxes, Current [Member] | Alabama Power [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | 2,000,000 | |||||||||||||||
Accrued Income Taxes, Current [Member] | Southern Power [Member] | Deferred Tax Liability, Noncurrent [Member] | ||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||
Prior Period Reclassification Adjustment | $ 2,000,000 |
Retirement Benefits - Actuarial
Retirement Benefits - Actuarial Assumptions 1 (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.67% | 4.17% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 6.97% | 7.15% | 7.13% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.51% | 4.04% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Alabama Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.67% | 4.18% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 7.17% | 7.34% | 7.36% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.51% | 4.04% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Georgia Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.65% | 4.18% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 6.48% | 6.75% | 6.74% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.49% | 4.03% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Gulf Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.71% | 4.18% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 8.07% | 8.08% | 8.04% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.51% | 4.04% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Mississippi Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.69% | 4.17% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Long-term return on plan assets on net periodic benefit costs | 7.23% | 7.30% | 7.04% |
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Discount rate, benefit obligation | 4.47% | 4.03% | |
Annual salary increase, benefit obligation | 4.46% | 3.59% | |
Interest Costs [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.17% | 5.02% | 4.26% |
Interest Costs [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.04% | 4.85% | 4.05% |
Interest Costs [Member] | Alabama Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% |
Interest Costs [Member] | Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.04% | 4.86% | 4.06% |
Interest Costs [Member] | Georgia Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% |
Interest Costs [Member] | Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.03% | 4.85% | 4.04% |
Interest Costs [Member] | Gulf Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% |
Interest Costs [Member] | Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.04% | 4.86% | 4.06% |
Interest Costs [Member] | Mississippi Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.17% | 5.01% | 4.26% |
Interest Costs [Member] | Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.03% | 4.85% | 4.04% |
Service Costs [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.48% | 5.02% | 4.26% |
Service Costs [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.39% | 4.85% | 4.05% |
Service Costs [Member] | Alabama Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.49% | 5.02% | 4.27% |
Service Costs [Member] | Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.40% | 4.86% | 4.06% |
Service Costs [Member] | Georgia Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.49% | 5.02% | 4.27% |
Service Costs [Member] | Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.39% | 4.85% | 4.04% |
Service Costs [Member] | Gulf Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.48% | 5.02% | 4.27% |
Service Costs [Member] | Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.38% | 4.86% | 4.06% |
Service Costs [Member] | Mississippi Power [Member] | Pension Plans [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.49% | 5.01% | 4.26% |
Service Costs [Member] | Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Pension Plans and Postretirement Plans | |||
Discount rate on net periodic benefit costs | 4.38% | 4.85% | 4.04% |
Retirement Benefits - Schedule
Retirement Benefits - Schedule Of Health Care Cost Trend Rates (Details) - Other Postretirement Benefit Plan [Member] | 12 Months Ended |
Dec. 31, 2015 | |
Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,025 |
Alabama Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Alabama Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Alabama Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,025 |
Georgia Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Georgia Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Georgia Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,025 |
Gulf Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Gulf Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Gulf Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,025 |
Mississippi Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Mississippi Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 5.50% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,024 |
Mississippi Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 10.00% |
Ultimate Cost Trend Rate | 4.50% |
Year That Ultimate Rate Is Reached | 2,025 |
Retirement Benefits - Actuari56
Retirement Benefits - Actuarial Assumptions 2 (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | $ 119 |
1 Percent decrease on benefit obligation | (102) |
1 Percent increase on service and interest costs | 4 |
1 Percent decrease on service and interest costs | (4) |
Alabama Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 29 |
1 Percent decrease on benefit obligation | (25) |
1 Percent increase on service and interest costs | 1 |
1 Percent decrease on service and interest costs | (1) |
Georgia Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 58 |
1 Percent decrease on benefit obligation | (50) |
1 Percent increase on service and interest costs | 2 |
1 Percent decrease on service and interest costs | (2) |
Gulf Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 4 |
1 Percent decrease on benefit obligation | (3) |
1 Percent increase on service and interest costs | 0 |
1 Percent decrease on service and interest costs | 0 |
Mississippi Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 5 |
1 Percent decrease on benefit obligation | (5) |
1 Percent increase on service and interest costs | 0 |
1 Percent decrease on service and interest costs | $ 0 |
Retirement Benefits - Changes i
Retirement Benefits - Changes in Projected Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | $ 10,909 | $ 8,863 | |
Service cost | 257 | 213 | $ 232 |
Interest cost | 445 | 435 | 389 |
Benefits paid | (487) | (382) | |
Actuarial loss (gain) | (582) | 1,780 | |
Balance at end of year | 10,542 | 10,909 | 8,863 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 9,690 | 8,733 | |
Actual return (loss) on plan assets | (14) | 797 | |
Employer contributions | 45 | 542 | |
Fair value of plan assets at end of year | 9,234 | 9,690 | 8,733 |
Accrued liability | (1,308) | (1,219) | |
Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 1,986 | 1,682 | |
Service cost | 23 | 21 | 24 |
Interest cost | 78 | 79 | 74 |
Benefits paid | (102) | (102) | |
Plan amendments | 34 | (2) | |
Actuarial loss (gain) | (38) | 300 | |
Retiree drug subsidy | 8 | 8 | |
Balance at end of year | 1,989 | 1,986 | 1,682 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 900 | 901 | |
Actual return (loss) on plan assets | (12) | 54 | |
Employer contributions | 39 | 39 | |
Benefits paid, net of drug subsidy | (94) | (94) | |
Fair value of plan assets at end of year | 833 | 900 | 901 |
Accrued liability | (1,156) | (1,086) | |
Georgia Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 3,781 | 3,116 | |
Service cost | 73 | 62 | 69 |
Interest cost | 154 | 153 | 138 |
Benefits paid | (188) | (149) | |
Actuarial loss (gain) | (205) | 599 | |
Balance at end of year | 3,615 | 3,781 | 3,116 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 3,383 | 3,085 | |
Actual return (loss) on plan assets | (13) | 285 | |
Employer contributions | 14 | 162 | |
Fair value of plan assets at end of year | 3,196 | 3,383 | 3,085 |
Accrued liability | (419) | (398) | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 864 | 723 | |
Service cost | 7 | 6 | 7 |
Interest cost | 34 | 34 | 31 |
Benefits paid | (45) | (44) | |
Plan amendments | 12 | 0 | |
Actuarial loss (gain) | (22) | 142 | |
Retiree drug subsidy | 4 | 3 | |
Balance at end of year | 854 | 864 | 723 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 395 | 407 | |
Actual return (loss) on plan assets | (6) | 21 | |
Employer contributions | 10 | 8 | |
Benefits paid, net of drug subsidy | (41) | (41) | |
Fair value of plan assets at end of year | 358 | 395 | 407 |
Accrued liability | (496) | (469) | |
Alabama Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 2,592 | 2,112 | |
Service cost | 59 | 48 | 52 |
Interest cost | 106 | 103 | 93 |
Benefits paid | (120) | (100) | |
Actuarial loss (gain) | (131) | 429 | |
Balance at end of year | 2,506 | 2,592 | 2,112 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 2,396 | 2,278 | |
Actual return (loss) on plan assets | (9) | 207 | |
Employer contributions | 12 | 11 | |
Fair value of plan assets at end of year | 2,279 | 2,396 | 2,278 |
Accrued liability | (227) | (196) | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 503 | 431 | |
Service cost | 6 | 5 | 6 |
Interest cost | 20 | 20 | 19 |
Benefits paid | (27) | (27) | |
Plan amendments | 7 | 0 | |
Actuarial loss (gain) | (7) | 71 | |
Retiree drug subsidy | 3 | 3 | |
Balance at end of year | 505 | 503 | 431 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 392 | 389 | |
Actual return (loss) on plan assets | (6) | 23 | |
Employer contributions | 1 | 4 | |
Benefits paid, net of drug subsidy | (24) | (24) | |
Fair value of plan assets at end of year | 363 | 392 | 389 |
Accrued liability | (142) | (111) | |
Gulf Power [Member] | |||
Change in benefit obligation | |||
Service cost | 12 | 10 | 11 |
Interest cost | 20 | 19 | 17 |
Gulf Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 491 | 395 | |
Service cost | 12 | 10 | |
Interest cost | 20 | 19 | |
Benefits paid | (20) | (16) | |
Actuarial loss (gain) | (23) | 83 | |
Balance at end of year | 480 | 491 | 395 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 435 | 386 | |
Actual return (loss) on plan assets | 4 | 34 | |
Employer contributions | 1 | 31 | |
Fair value of plan assets at end of year | 420 | 435 | 386 |
Accrued liability | (60) | (56) | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 78 | 69 | |
Service cost | 1 | 1 | 1 |
Interest cost | 3 | 3 | 3 |
Benefits paid | (4) | (4) | |
Plan amendments | 4 | (2) | |
Actuarial loss (gain) | (1) | 11 | |
Retiree drug subsidy | 0 | 0 | |
Balance at end of year | 81 | 78 | 69 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 18 | 17 | |
Actual return (loss) on plan assets | 0 | 2 | |
Employer contributions | 3 | 3 | |
Benefits paid, net of drug subsidy | (4) | (4) | |
Fair value of plan assets at end of year | 17 | 18 | 17 |
Accrued liability | (64) | (60) | |
Mississippi Power [Member] | |||
Change in benefit obligation | |||
Service cost | 13 | 10 | 11 |
Interest cost | 21 | 20 | 18 |
Change in plan assets | |||
Employer contributions | 5 | 5 | 4 |
Mississippi Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 513 | 409 | |
Service cost | 13 | 10 | |
Interest cost | 21 | 20 | |
Benefits paid | (22) | (17) | |
Actuarial loss (gain) | (25) | 91 | |
Balance at end of year | 500 | 513 | 409 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 446 | 387 | |
Actual return (loss) on plan assets | 4 | 40 | |
Employer contributions | 2 | 36 | |
Fair value of plan assets at end of year | 430 | 446 | 387 |
Accrued liability | (70) | (67) | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 96 | 81 | |
Service cost | 1 | 1 | 1 |
Interest cost | 4 | 4 | 4 |
Benefits paid | (5) | (5) | |
Plan amendments | 1 | 0 | |
Actuarial loss (gain) | (1) | 14 | |
Retiree drug subsidy | 1 | 1 | |
Balance at end of year | 97 | 96 | 81 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 24 | 23 | |
Actual return (loss) on plan assets | 0 | 2 | |
Employer contributions | 3 | 3 | |
Benefits paid, net of drug subsidy | (4) | (4) | |
Fair value of plan assets at end of year | 23 | 24 | $ 23 |
Accrued liability | $ (74) | $ (72) |
Retirement Benefits - Amounts R
Retirement Benefits - Amounts Recognized in Balance Sheets and Amounts in AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | $ 4,989 | $ 4,334 |
Other current liabilities | (590) | (374) |
Other regulatory liabilities, deferred | (254) | (398) |
Employee benefit obligations | (2,582) | (2,432) |
Accumulated OCI | (130) | (128) |
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 | 5,564 | 4,664 |
Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 2,998 | 3,073 |
Other current liabilities | (46) | (42) |
Employee benefit obligations | (1,262) | (1,177) |
Accumulated OCI | 125 | 134 |
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 | 30 | 55 |
Net (Gain) Loss | 3,093 | 3,152 |
Prior Service Cost, Estimated | 14 | |
Net (Gain) Loss, Estimated | 151 | |
Pension Plans [Member] | AOCI Attributable to Parent [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 3 | 4 |
Net (Gain) Loss | 122 | 130 |
Prior Service Cost, Estimated | 1 | |
Net (Gain) Loss, Estimated | 6 | |
Pension Plans [Member] | Regulatory Assets [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 27 | 51 |
Net (Gain) Loss | 2,971 | 3,022 |
Prior Service Cost, Estimated | 13 | |
Net (Gain) Loss, Estimated | 145 | |
Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 433 | 387 |
Other current liabilities | (4) | (4) |
Other regulatory liabilities, deferred | (22) | (21) |
Employee benefit obligations | (1,152) | (1,082) |
Accumulated OCI | 8 | 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 | 32 | 2 |
Net (Gain) Loss | 387 | 372 |
Other Postretirement Benefits [Member] | AOCI Attributable to Parent [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 0 | 0 |
Net (Gain) Loss | 8 | 8 |
Other Postretirement Benefits [Member] | Regulatory Assets [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 32 | 2 |
Net (Gain) Loss | 379 | 364 |
Prior Service Cost, Estimated | 6 | |
Net (Gain) Loss, Estimated | 14 | |
Alabama Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 1,114 | 1,063 |
Other current liabilities | (39) | (40) |
Other regulatory liabilities, deferred | (136) | (239) |
Employee benefit obligations | (388) | (326) |
Accumulated OCI | (32) | (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 | 791 | 738 |
Alabama Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 822 | 827 |
Other current liabilities | (11) | (10) |
Employee benefit obligations | (216) | (186) |
Alabama Power [Member] | Pension Plans [Member] | Regulatory Assets [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 6 | 12 |
Net (Gain) Loss | 816 | 815 |
Prior Service Cost, Estimated | 3 | |
Net (Gain) Loss, Estimated | (40) | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 95 | 68 |
Other regulatory liabilities, deferred | (13) | (14) |
Employee benefit obligations | (142) | (111) |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Regulatory Assets [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 82 | 54 |
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 | 19 | 15 |
Net (Gain) Loss | 63 | 39 |
Prior Service Cost, Estimated | 4 | |
Net (Gain) Loss, Estimated | 2 | |
Georgia Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 2,152 | 1,753 |
Other current liabilities | (143) | (172) |
Employee benefit obligations | (949) | (903) |
Accumulated OCI | (15) | (8) |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Net Regulatory Assets | 2,933 | 2,529 |
Georgia Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 1,076 | 1,102 |
Other current liabilities | (13) | (12) |
Employee benefit obligations | (406) | (386) |
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 | 8 | 17 |
Net (Gain) Loss | 1,068 | 1,085 |
Prior Service Cost, Estimated | 5 | |
Net (Gain) Loss, Estimated | 55 | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 223 | 213 |
Employee benefit obligations | (496) | (469) |
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 | 8 | (5) |
Net (Gain) Loss | 215 | 218 |
Prior Service Cost, Estimated | 1 | |
Net (Gain) Loss, Estimated | 9 | |
Gulf Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 427 | 416 |
Other current liabilities | (40) | (22) |
Other regulatory liabilities, deferred | (47) | (48) |
Employee benefit obligations | (129) | (121) |
Accumulated OCI | 0 | (1) |
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 | 296 | 319 |
Gulf Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 142 | 146 |
Other current liabilities | (1) | (1) |
Employee benefit obligations | (59) | (55) |
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 | 3 |
Net (Gain) Loss | 140 | 143 |
Prior Service Cost, Estimated | 1 | |
Net (Gain) Loss, Estimated | 6 | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 10 | 6 |
Other current liabilities | (1) | (1) |
Other regulatory liabilities, deferred | (5) | (4) |
Employee benefit obligations | (63) | (59) |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Regulatory Assets [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 5 | 2 |
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 | (2) |
Net (Gain) Loss | 5 | 4 |
Prior Service Cost, Estimated | 0 | |
Net (Gain) Loss, Estimated | 0 | |
Mississippi Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 525 | 385 |
Other current liabilities | (74) | (46) |
Other regulatory liabilities, deferred | (71) | (64) |
Employee benefit obligations | (153) | (148) |
Accumulated OCI | (6) | (7) |
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 | 667 | 172 |
Mississippi Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 144 | 151 |
Other current liabilities | (3) | (2) |
Employee benefit obligations | (67) | (65) |
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 | 3 |
Net (Gain) Loss | 142 | 148 |
Prior Service Cost, Estimated | 1 | |
Net (Gain) Loss, Estimated | 7 | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 21 | 18 |
Other regulatory liabilities, deferred | (3) | (2) |
Employee benefit obligations | (74) | (72) |
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 | (2) |
Net (Gain) Loss | (18) | 18 |
Prior Service Cost, Estimated | 0 | |
Net (Gain) Loss, Estimated | 1 | |
Net Regulatory Assets | $ (18) | $ 16 |
Retirement Benefits - Component
Retirement Benefits - Components of Accumulated OCI and Changes in Regulatory Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Postretirement Benefits [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | $ (387) | $ (372) | |
Reclassification adjustments | |||
Amortization of prior service costs | 21 | 6 | $ 21 |
Net periodic benefit cost | 64 | 47 | 63 |
Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 366 | 73 | |
Net (gain) loss | 33 | 301 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (379) | (364) | |
Change in prior service costs | (33) | 2 | |
Reclassification adjustments | |||
Amortization of prior service costs | (4) | (4) | |
Amortization of net gain (loss) | (17) | (2) | |
Total reclassification adjustments | (21) | (6) | |
Net periodic benefit cost | 45 | 293 | |
Ending Balance | 411 | 366 | 73 |
Other Postretirement Benefits [Member] | AOCI Attributable to Parent [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 8 | 1 | |
Net (gain) loss | 0 | 7 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (8) | (8) | |
Change in prior service costs | 0 | 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 | 0 | 7 | |
Ending Balance | 8 | 8 | 1 |
Pension Plan [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (3,093) | (3,152) | |
Reclassification adjustments | |||
Amortization of prior service costs | 25 | 26 | 27 |
Net periodic benefit cost | 218 | 139 | 245 |
Pension Plan [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 3,073 | 1,651 | |
Net (gain) loss | 155 | 1,552 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (2,971) | (3,022) | |
Change in prior service costs | (1) | ||
Reclassification adjustments | |||
Amortization of prior service costs | (24) | (25) | |
Amortization of net gain (loss) | (206) | (106) | |
Total reclassification adjustments | (230) | (131) | |
Net periodic benefit cost | (75) | 1,422 | |
Ending Balance | 2,998 | 3,073 | 1,651 |
Pension Plan [Member] | AOCI Attributable to Parent [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 134 | 64 | |
Net (gain) loss | 1 | 75 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (122) | (130) | |
Change in prior service costs | 0 | ||
Reclassification adjustments | |||
Amortization of prior service costs | (1) | (1) | |
Amortization of net gain (loss) | (9) | (4) | |
Total reclassification adjustments | (10) | (5) | |
Net periodic benefit cost | (9) | 70 | |
Ending Balance | 125 | 134 | 64 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (215) | (218) | |
Reclassification adjustments | |||
Amortization of prior service costs | 11 | 2 | 12 |
Net periodic benefit cost | 28 | 17 | 26 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 213 | 69 | |
Net (gain) loss | 9 | 146 | |
Change in prior service costs | (12) | 0 | |
Reclassification adjustments | |||
Amortization of net gain (loss) | (11) | (2) | |
Net periodic benefit cost | 10 | 144 | |
Ending Balance | 223 | 213 | 69 |
Georgia Power [Member] | Pension Plan [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (1,068) | (1,085) | |
Reclassification adjustments | |||
Amortization of prior service costs | 9 | 10 | 10 |
Net periodic benefit cost | 61 | 38 | 79 |
Georgia Power [Member] | Pension Plan [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 1,102 | 610 | |
Net (gain) loss | 59 | 543 | |
Reclassification adjustments | |||
Amortization of prior service costs | (9) | (10) | |
Amortization of net gain (loss) | (76) | (41) | |
Total reclassification adjustments | (85) | (51) | |
Net periodic benefit cost | (26) | 492 | |
Ending Balance | 1,076 | 1,102 | 610 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 5 | 4 | 5 |
Net periodic benefit cost | 5 | 4 | 7 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 54 | (15) | |
Net (gain) loss | 25 | 73 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (63) | (39) | |
Change in prior service costs | (8) | 0 | |
Reclassification adjustments | |||
Amortization of prior service costs | (3) | (4) | |
Amortization of net gain (loss) | (2) | 0 | |
Total reclassification adjustments | (5) | (4) | |
Net periodic benefit cost | 28 | 69 | |
Ending Balance | 82 | 54 | (15) |
Alabama Power [Member] | Pension Plan [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 6 | 7 | 7 |
Net periodic benefit cost | 48 | 21 | 47 |
Alabama Power [Member] | Pension Plan [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 827 | 476 | |
Net (gain) loss | 56 | 389 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (816) | (815) | |
Reclassification adjustments | |||
Amortization of prior service costs | (6) | (7) | |
Amortization of net gain (loss) | (55) | (31) | |
Total reclassification adjustments | (61) | (38) | |
Net periodic benefit cost | (5) | 351 | |
Ending Balance | 822 | 827 | 476 |
Gulf Power [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 1 | 1 | 1 |
Net periodic benefit cost | 10 | 7 | 12 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 0 | 0 | 0 |
Net periodic benefit cost | 3 | 3 | 3 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 2 | (7) | |
Net (gain) loss | 1 | 11 | |
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (5) | (4) | |
Change in prior service costs | (2) | 2 | |
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 | 9 | |
Ending Balance | 5 | 2 | (7) |
Gulf Power [Member] | Pension Plan [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (140) | (143) | |
Gulf Power [Member] | Pension Plan [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 146 | 75 | |
Net (gain) loss | 6 | 77 | |
Reclassification adjustments | |||
Amortization of prior service costs | (1) | (1) | |
Amortization of net gain (loss) | (9) | (5) | |
Total reclassification adjustments | (10) | (6) | |
Net periodic benefit cost | (4) | 71 | |
Ending Balance | 142 | 146 | 75 |
Mississippi Power [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 1 | 1 | 1 |
Net periodic benefit cost | 12 | 7 | 13 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | 18 | (18) | |
Reclassification adjustments | |||
Amortization of prior service costs | 1 | 0 | 0 |
Net periodic benefit cost | 4 | 3 | 4 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 16 | 2 | |
Net (gain) loss | 0 | 14 | |
Change in prior service costs | (3) | 0 | |
Reclassification adjustments | |||
Amortization of net gain (loss) | (1) | 0 | |
Total reclassification adjustments | (1) | 0 | |
Net periodic benefit cost | 2 | 14 | |
Ending Balance | 18 | 16 | 2 |
Mississippi Power [Member] | Pension Plan [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | (142) | (148) | |
Mississippi Power [Member] | Pension Plan [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 151 | 78 | |
Net (gain) loss | 4 | 79 | |
Reclassification adjustments | |||
Amortization of prior service costs | (1) | (1) | |
Amortization of net gain (loss) | (10) | (5) | |
Total reclassification adjustments | (11) | (6) | |
Net periodic benefit cost | (7) | 73 | |
Ending Balance | $ 144 | $ 151 | $ 78 |
Retirement Benefits - Compone60
Retirement Benefits - Components of Net Periodic Benefit Cost and Estimated Future Benefit Payments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | $ 23 | $ 21 | $ 24 |
Interest cost | 78 | 79 | 74 |
Expected return on plan assets | (58) | (59) | (56) |
Net amortization | 21 | 6 | 21 |
Net periodic benefit cost | 64 | 47 | 63 |
Benefit Payments | |||
Benefit Payments, 2016 | 123 | ||
Benefit Payments, 2017 | 128 | ||
Benefit Payments, 2018 | 133 | ||
Benefit Payments, 2019 | 137 | ||
Benefit Payments, 2020 | 139 | ||
Benefit Payments, 2021 to 2025 | 711 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2016 | (9) | ||
Subsidy Receipts, 2017 | (10) | ||
Subsidy Receipts, 2018 | (11) | ||
Subsidy Receipts, 2019 | (12) | ||
Subsidy Receipts, 2020 | (12) | ||
Subsidy Receipts, 2021 to 2025 | (65) | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2016 | 114 | ||
Benefit Payments and Subsidy Receipts, 2017 | 118 | ||
Benefit Payments and Subsidy Receipts, 2018 | 122 | ||
Benefit Payments and Subsidy Receipts, 2019 | 125 | ||
Benefit Payments and Subsidy Receipts, 2020 | 127 | ||
Benefit Payments and Subsidy Receipts, 2021 to 2025 | 646 | ||
Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 257 | 213 | 232 |
Interest cost | 445 | 435 | 389 |
Expected return on plan assets | (724) | (645) | (603) |
Recognized net (gain) loss | 215 | 110 | 200 |
Net amortization | 25 | 26 | 27 |
Net periodic benefit cost | 218 | 139 | 245 |
Benefit Payments | |||
Benefit Payments, 2016 | 450 | ||
Benefit Payments, 2017 | 478 | ||
Benefit Payments, 2018 | 501 | ||
Benefit Payments, 2019 | 527 | ||
Benefit Payments, 2020 | 554 | ||
Benefit Payments, 2021 to 2025 | 3,141 | ||
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 6 | 5 | 6 |
Interest cost | 20 | 20 | 19 |
Expected return on plan assets | (26) | (25) | (23) |
Net amortization | 5 | 4 | 5 |
Net periodic benefit cost | 5 | 4 | 7 |
Benefit Payments | |||
Benefit Payments, 2016 | 33 | ||
Benefit Payments, 2017 | 34 | ||
Benefit Payments, 2018 | 34 | ||
Benefit Payments, 2019 | 35 | ||
Benefit Payments, 2020 | 36 | ||
Benefit Payments, 2021 to 2025 | 184 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2016 | (3) | ||
Subsidy Receipts, 2017 | (3) | ||
Subsidy Receipts, 2018 | (3) | ||
Subsidy Receipts, 2019 | (4) | ||
Subsidy Receipts, 2020 | (4) | ||
Subsidy Receipts, 2021 to 2025 | (20) | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2016 | 30 | ||
Benefit Payments and Subsidy Receipts, 2017 | 31 | ||
Benefit Payments and Subsidy Receipts, 2018 | 31 | ||
Benefit Payments and Subsidy Receipts, 2019 | 31 | ||
Benefit Payments and Subsidy Receipts, 2020 | 32 | ||
Benefit Payments and Subsidy Receipts, 2021 to 2025 | 164 | ||
Alabama Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 59 | 48 | 52 |
Interest cost | 106 | 103 | 93 |
Expected return on plan assets | (178) | (168) | (157) |
Recognized net (gain) loss | 55 | 31 | 52 |
Net amortization | 6 | 7 | 7 |
Net periodic benefit cost | 48 | 21 | 47 |
Benefit Payments | |||
Benefit Payments, 2016 | 114 | ||
Benefit Payments, 2017 | 119 | ||
Benefit Payments, 2018 | 124 | ||
Benefit Payments, 2019 | 129 | ||
Benefit Payments, 2020 | 134 | ||
Benefit Payments, 2021 to 2025 | 740 | ||
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 7 | 6 | 7 |
Interest cost | 34 | 34 | 31 |
Expected return on plan assets | (24) | (25) | (24) |
Net amortization | 11 | 2 | 12 |
Net periodic benefit cost | 28 | 17 | 26 |
Benefit Payments | |||
Benefit Payments, 2016 | 53 | ||
Benefit Payments, 2017 | 55 | ||
Benefit Payments, 2018 | 58 | ||
Benefit Payments, 2019 | 59 | ||
Benefit Payments, 2020 | 60 | ||
Benefit Payments, 2021 to 2025 | 305 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2016 | (4) | ||
Subsidy Receipts, 2017 | (4) | ||
Subsidy Receipts, 2018 | (5) | ||
Subsidy Receipts, 2019 | (5) | ||
Subsidy Receipts, 2020 | (5) | ||
Subsidy Receipts, 2021 to 2025 | (28) | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2016 | 49 | ||
Benefit Payments and Subsidy Receipts, 2017 | 51 | ||
Benefit Payments and Subsidy Receipts, 2018 | 53 | ||
Benefit Payments and Subsidy Receipts, 2019 | 54 | ||
Benefit Payments and Subsidy Receipts, 2020 | 55 | ||
Benefit Payments and Subsidy Receipts, 2021 to 2025 | 277 | ||
Georgia Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 73 | 62 | 69 |
Interest cost | 154 | 153 | 138 |
Expected return on plan assets | (251) | (228) | (212) |
Recognized net (gain) loss | 76 | 41 | 74 |
Net amortization | 9 | 10 | 10 |
Net periodic benefit cost | 61 | 38 | 79 |
Benefit Payments | |||
Benefit Payments, 2016 | 168 | ||
Benefit Payments, 2017 | 176 | ||
Benefit Payments, 2018 | 183 | ||
Benefit Payments, 2019 | 189 | ||
Benefit Payments, 2020 | 197 | ||
Benefit Payments, 2021 to 2025 | 1,085 | ||
Gulf Power [Member] | |||
Components of net periodic | |||
Service cost | 12 | 10 | 11 |
Interest cost | 20 | 19 | 17 |
Expected return on plan assets | (32) | (28) | (26) |
Recognized net (gain) loss | 9 | 5 | 9 |
Net amortization | 1 | 1 | 1 |
Net periodic benefit cost | 10 | 7 | 12 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 1 | 1 | 1 |
Interest cost | 3 | 3 | 3 |
Expected return on plan assets | (1) | (1) | (1) |
Net amortization | 0 | 0 | 0 |
Net periodic benefit cost | 3 | 3 | 3 |
Benefit Payments | |||
Benefit Payments, 2016 | 5 | ||
Benefit Payments, 2017 | 5 | ||
Benefit Payments, 2018 | 6 | ||
Benefit Payments, 2019 | 6 | ||
Benefit Payments, 2020 | 6 | ||
Benefit Payments, 2021 to 2025 | 29 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2016 | 0 | ||
Subsidy Receipts, 2017 | 0 | ||
Subsidy Receipts, 2018 | 0 | ||
Subsidy Receipts, 2019 | (1) | ||
Subsidy Receipts, 2020 | (1) | ||
Subsidy Receipts, 2021 to 2025 | (3) | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2016 | 5 | ||
Benefit Payments and Subsidy Receipts, 2017 | 5 | ||
Benefit Payments and Subsidy Receipts, 2018 | 6 | ||
Benefit Payments and Subsidy Receipts, 2019 | 5 | ||
Benefit Payments and Subsidy Receipts, 2020 | 5 | ||
Benefit Payments and Subsidy Receipts, 2021 to 2025 | 26 | ||
Gulf Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 12 | 10 | |
Interest cost | 20 | 19 | |
Benefit Payments | |||
Benefit Payments, 2016 | 19 | ||
Benefit Payments, 2017 | 20 | ||
Benefit Payments, 2018 | 21 | ||
Benefit Payments, 2019 | 22 | ||
Benefit Payments, 2020 | 24 | ||
Benefit Payments, 2021 to 2025 | 139 | ||
Mississippi Power [Member] | |||
Components of net periodic | |||
Service cost | 13 | 10 | 11 |
Interest cost | 21 | 20 | 18 |
Expected return on plan assets | (33) | (29) | (27) |
Recognized net (gain) loss | 10 | 5 | 10 |
Net amortization | 1 | 1 | 1 |
Net periodic benefit cost | 12 | 7 | 13 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 1 | 1 | 1 |
Interest cost | 4 | 4 | 4 |
Expected return on plan assets | (2) | (2) | (1) |
Net amortization | 1 | 0 | 0 |
Net periodic benefit cost | 4 | 3 | $ 4 |
Benefit Payments | |||
Benefit Payments, 2016 | 6 | ||
Benefit Payments, 2017 | 6 | ||
Benefit Payments, 2018 | 6 | ||
Benefit Payments, 2019 | 7 | ||
Benefit Payments, 2020 | 7 | ||
Benefit Payments, 2021 to 2025 | 36 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2016 | 0 | ||
Subsidy Receipts, 2017 | (1) | ||
Subsidy Receipts, 2018 | (1) | ||
Subsidy Receipts, 2019 | (1) | ||
Subsidy Receipts, 2020 | (1) | ||
Subsidy Receipts, 2021 to 2025 | (2) | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2016 | 6 | ||
Benefit Payments and Subsidy Receipts, 2017 | 5 | ||
Benefit Payments and Subsidy Receipts, 2018 | 5 | ||
Benefit Payments and Subsidy Receipts, 2019 | 6 | ||
Benefit Payments and Subsidy Receipts, 2020 | 6 | ||
Benefit Payments and Subsidy Receipts, 2021 to 2025 | 34 | ||
Mississippi Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 13 | 10 | |
Interest cost | 21 | $ 20 | |
Benefit Payments | |||
Benefit Payments, 2016 | 20 | ||
Benefit Payments, 2017 | 21 | ||
Benefit Payments, 2018 | 22 | ||
Benefit Payments, 2019 | 24 | ||
Benefit Payments, 2020 | 25 | ||
Benefit Payments, 2021 to 2025 | $ 146 |
Retirement Benefits - Pension P
Retirement Benefits - Pension Plan and Other Postretirement Benefit Plan Assets (Details) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 30.00% |
Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 23.00% |
Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 23.00% | 27.00% |
Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 16.00% | 14.00% |
Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 42.00% | |
Defined Benefit Plan Assets | 38.00% | 41.00% |
Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 23.00% | 23.00% |
Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 26.00% | 26.00% |
Other Postretirement Benefits [Member] | Global fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 4.00% | |
Defined Benefit Plan Assets | 4.00% | 3.00% |
Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 1.00% | |
Defined Benefit Plan Assets | 1.00% | 0.00% |
Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 5.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 2.00% |
Alabama Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Alabama Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 30.00% |
Alabama Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 23.00% |
Alabama Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 23.00% | 27.00% |
Alabama Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Alabama Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 16.00% | 14.00% |
Alabama Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 48.00% | |
Defined Benefit Plan Assets | 45.00% | 48.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 20.00% | |
Defined Benefit Plan Assets | 20.00% | 20.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 27.00% | 26.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 1.00% | |
Defined Benefit Plan Assets | 1.00% | 0.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 4.00% | |
Defined Benefit Plan Assets | 5.00% | 4.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 2.00% |
Georgia Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Georgia Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 30.00% |
Georgia Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 23.00% |
Georgia Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 23.00% | 27.00% |
Georgia Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Georgia Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 16.00% | 14.00% |
Georgia Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 40.00% | |
Defined Benefit Plan Assets | 34.00% | 38.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 27.00% | 26.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 25.00% | 24.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Global fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 8.00% | 7.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 1.00% | |
Defined Benefit Plan Assets | 0.00% | 0.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 4.00% | |
Defined Benefit Plan Assets | 4.00% | 4.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 2.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Gulf Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Gulf Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 30.00% |
Gulf Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 23.00% |
Gulf Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 23.00% | 27.00% |
Gulf Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Gulf Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 16.00% | 14.00% |
Gulf Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 29.00% | 29.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 22.00% | 22.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 25.00% | 29.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 16.00% | 14.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Mississippi Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Mississippi Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 30.00% |
Mississippi Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 23.00% |
Mississippi Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 23.00% | 27.00% |
Mississippi Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Mississippi Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 16.00% | 14.00% |
Mississippi Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 6.00% | 5.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 24.00% | 24.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 20.00% | |
Defined Benefit Plan Assets | 18.00% | 19.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 38.00% | |
Defined Benefit Plan Assets | 38.00% | 41.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 1.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 11.00% | |
Defined Benefit Plan Assets | 13.00% | 11.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 7.00% | |
Defined Benefit Plan Assets | 5.00% | 4.00% |
Retirement Benefits - Fair Valu
Retirement Benefits - Fair Values of Pension Plan and Other Postretirement Benefit Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | $ 9,083 | $ 9,647 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | (1) | (2) |
Fair Value, Plan Assets and Liabilities | 9,082 | 9,645 |
Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2,313 | 2,408 |
Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2,180 | 2,056 |
Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 454 | 699 |
Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 199 | 188 |
Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,140 | 1,135 |
Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 500 | 514 |
Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 145 | 663 |
Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,517 | 1,414 |
Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 635 | 570 |
Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 834 | 905 |
Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 158 | 203 |
Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 104 | 103 |
Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 22 | 29 |
Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 6 |
Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 38 | 39 |
Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 42 | 41 |
Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 20 | 36 |
Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 370 | 381 |
Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 52 | 48 |
Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 19 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3,121 | 3,070 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | (1) | (2) |
Fair Value, Plan Assets and Liabilities | 3,120 | 3,068 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,632 | 1,704 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,190 | 1,070 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 3 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 299 | 293 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 168 | 203 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 106 | 147 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 40 | 36 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 11 | 9 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 11 | 11 |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4,109 | 4,886 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | 0 | 0 |
Fair Value, Plan Assets and Liabilities | 4,109 | 4,886 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 681 | 704 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 990 | 986 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 454 | 699 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 199 | 188 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,140 | 1,135 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 500 | 514 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 145 | 660 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 604 | 646 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 52 | 56 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 64 | 67 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 22 | 29 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 6 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 38 | 39 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 42 | 41 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 9 | 27 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 370 | 381 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | 0 | 0 |
Fair Value, Plan Assets and Liabilities | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,853 | 1,691 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | 0 | 0 |
Fair Value, Plan Assets and Liabilities | 1,853 | 1,691 |
Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,218 | 1,121 |
Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 635 | 570 |
Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 62 | 56 |
Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 41 | 37 |
Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 19 |
Alabama Power [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2,241 | 2,385 |
Alabama Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 571 | 595 |
Alabama Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 538 | 508 |
Alabama Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 112 | 173 |
Alabama Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 49 | 47 |
Alabama Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 280 | 280 |
Alabama Power [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 123 | 127 |
Alabama Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 36 | 164 |
Alabama Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 375 | 350 |
Alabama Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 157 | 141 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 361 | 391 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 65 | 84 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 26 | 25 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 8 | 10 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 13 | 14 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 6 | 6 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 8 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 212 | 217 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 19 | 18 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 7 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 771 | 759 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 403 | 421 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 294 | 264 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 1 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 74 | 73 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 77 | 94 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 57 | 76 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 14 | 13 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 5 | 5 |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,012 | 1,208 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 168 | 174 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 244 | 244 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 112 | 173 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 49 | 47 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 280 | 280 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 123 | 127 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 36 | 163 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 263 | 277 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 8 | 8 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 12 | 12 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 8 | 10 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 13 | 14 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 6 | 6 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 8 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 212 | 217 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Alabama Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 458 | 418 |
Alabama Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 301 | 277 |
Alabama Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 157 | 141 |
Alabama Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 20 |
Alabama Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 14 | 13 |
Alabama Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 7 |
Georgia Power [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3,143 | 3,368 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | (1) | |
Fair Value, Plan Assets and Liabilities | 3,367 | |
Georgia Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 801 | 841 |
Georgia Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 755 | 717 |
Georgia Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 157 | 244 |
Georgia Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 69 | 66 |
Georgia Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 394 | 398 |
Georgia Power [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 173 | 179 |
Georgia Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 50 | 231 |
Georgia Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 524 | 493 |
Georgia Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 220 | 199 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 364 | 401 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 66 | 93 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 53 | 56 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 5 | 7 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 12 | 12 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 30 | 29 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 16 | 19 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 158 | 162 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 15 | 15 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 6 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,080 | 1,071 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | (1) | |
Fair Value, Plan Assets and Liabilities | 1,070 | |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 565 | 595 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 412 | 373 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 1 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 103 | 102 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 55 | 75 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 30 | 53 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 12 | 11 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 10 | 8 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 3 |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1,422 | 1,707 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | 0 | |
Fair Value, Plan Assets and Liabilities | 1,707 | |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 236 | 246 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 343 | 344 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 157 | 244 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 69 | 66 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 394 | 398 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 173 | 179 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 50 | 230 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 290 | 308 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 36 | 40 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 41 | 45 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 5 | 7 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 12 | 12 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 30 | 29 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 6 | 11 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 158 | 162 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | 0 | |
Fair Value, Plan Assets and Liabilities | 0 | |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Georgia Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 641 | 590 |
Liabilities Fair Value | ||
Fair Value, Plan Liabilities | 0 | |
Fair Value, Plan Assets and Liabilities | 590 | |
Georgia Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 421 | 391 |
Georgia Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 220 | 199 |
Georgia Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 19 | 18 |
Georgia Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 12 | 12 |
Georgia Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 6 |
Gulf Power [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 412 | 433 |
Gulf Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 104 | 109 |
Gulf Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 99 | 92 |
Gulf Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 31 |
Gulf Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 9 | 8 |
Gulf Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 51 | 51 |
Gulf Power [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 23 | 23 |
Gulf Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 30 |
Gulf Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 69 | 63 |
Gulf Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 29 | 26 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 17 | 18 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4 | 4 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4 | 4 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 1 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 3 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 141 | 138 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 73 | 77 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 54 | 48 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 14 | 13 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 6 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 3 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 0 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 187 | 219 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 31 | 32 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 45 | 44 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 31 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 9 | 8 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 51 | 51 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 23 | 23 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 30 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 9 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 1 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 1 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Gulf Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 84 | 76 |
Gulf Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 55 | 50 |
Gulf Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 29 | 26 |
Gulf Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 3 |
Gulf Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Gulf Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Mississippi Power [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 423 | 443 |
Mississippi Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 108 | 110 |
Mississippi Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 101 | 94 |
Mississippi Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 32 |
Mississippi Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 9 | 9 |
Mississippi Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 53 | 53 |
Mississippi Power [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 23 | 24 |
Mississippi Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 30 |
Mississippi Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 71 | 65 |
Mississippi Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 30 | 26 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 23 | 24 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4 | 5 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4 | 4 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 6 | 6 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 2 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4 | 3 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 145 | 141 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 76 | 78 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 55 | 49 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 14 | 14 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 7 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 3 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 191 | 225 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 32 | 32 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 46 | 45 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 21 | 32 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 9 | 9 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 53 | 53 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 23 | 24 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 7 | 30 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 12 | 14 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 2 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 6 | 6 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 2 | 2 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 1 | 1 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 1 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 0 | 0 |
Mississippi Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 87 | 77 |
Mississippi Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 57 | 51 |
Mississippi Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Pension Plans [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 30 | 26 |
Mississippi Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 4 | 3 |
Mississippi Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | 3 | 2 |
Mississippi Power [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Assets Fair Value | ||
Fair Value, Plan Assets | $ 1 | $ 1 |
Retirement Benefits - Textual (
Retirement Benefits - Textual (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ 9,600,000,000 | $ 10,000,000,000 | |
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||
Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | $ 0 | ||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 191,000,000 | ||
Projected benefit obligations | 10,542,000,000 | $ 10,909,000,000 | $ 8,863,000,000 |
Total matching contributions | 45,000,000 | $ 542,000,000 | |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | $ 14,000,000 | ||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 35,000,000 | ||
Projected benefit obligations | 1,989,000,000 | $ 1,986,000,000 | $ 1,682,000,000 |
Total matching contributions | $ 39,000,000 | 39,000,000 | |
Alabama Power [Member] | |||
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 | $ 2,300,000,000 | $ 2,400,000,000 | |
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||
Alabama Power [Member] | Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 51,000,000 | ||
Projected benefit obligations | 2,506,000,000 | $ 2,592,000,000 | $ 2,112,000,000 |
Total matching contributions | $ 12,000,000 | $ 11,000,000 | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 9,000,000 | ||
Projected benefit obligations | 505,000,000 | $ 503,000,000 | $ 431,000,000 |
Total matching contributions | 1,000,000 | $ 4,000,000 | |
Georgia Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | $ 14,000,000 | ||
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | ||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||
Georgia Power [Member] | Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | $ 0 | ||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 66,000,000 | ||
Total accumulated benefit obligation for the pension plans | 3,300,000,000 | $ 3,500,000,000 | |
Projected benefit obligations | 3,615,000,000 | 3,781,000,000 | $ 3,116,000,000 |
Total matching contributions | $ 14,000,000 | $ 162,000,000 | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 17,000,000 | ||
Projected benefit obligations | 854,000,000 | $ 864,000,000 | $ 723,000,000 |
Total matching contributions | $ 10,000,000 | $ 8,000,000 | |
Gulf Power [Member] | |||
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 | ||
Gulf Power [Member] | Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 9,000,000 | ||
Total accumulated benefit obligation for the pension plans | 424,000,000 | $ 438,000,000 | |
Projected benefit obligations | 480,000,000 | 491,000,000 | $ 395,000,000 |
Total matching contributions | 1,000,000 | $ 31,000,000 | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | $ 0 | ||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 1,000,000 | ||
Projected benefit obligations | 81,000,000 | $ 78,000,000 | $ 69,000,000 |
Total matching contributions | $ 3,000,000 | 3,000,000 | |
Mississippi Power [Member] | |||
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 | $ 447,000,000 | 462,000,000 | |
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | ||
Total matching contributions | $ 5,000,000 | $ 5,000,000 | $ 4,000,000 |
Mississippi Power [Member] | Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 9,000,000 | ||
Projected benefit obligations | 500,000,000 | $ 513,000,000 | $ 409,000,000 |
Total matching contributions | $ 2,000,000 | $ 36,000,000 | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% |
Mortality Assumption Change | $ 2,000,000 | ||
Projected benefit obligations | 97,000,000 | $ 96,000,000 | $ 81,000,000 |
Total matching contributions | $ 3,000,000 | 3,000,000 | |
Employee Saving Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Matching limit of contribution by employer | 85.00% | ||
Maximum limit of contribution of employees base salary | 6.00% | ||
Total matching contributions | $ 92,000,000 | 87,000,000 | 84,000,000 |
Employee Saving Plan [Member] | Alabama Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Matching limit of contribution by employer | 85.00% | ||
Maximum limit of contribution of employees base salary | 6.00% | ||
Total matching contributions | $ 22,000,000 | 21,000,000 | 20,000,000 |
Employee Saving Plan [Member] | Georgia Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Matching limit of contribution by employer | 85.00% | ||
Maximum limit of contribution of employees base salary | 6.00% | ||
Total matching contributions | $ 26,000,000 | 25,000,000 | 24,000,000 |
Employee Saving Plan [Member] | Gulf Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Matching limit of contribution by employer | 85.00% | ||
Maximum limit of contribution of employees base salary | 6.00% | ||
Total matching contributions | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 |
Employee Saving Plan [Member] | Mississippi Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Matching limit of contribution by employer | 85.00% | ||
Maximum limit of contribution of employees base salary | 6.00% | ||
Qualified Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | $ 10,000,000,000 | ||
Qualified Pension Plans [Member] | Alabama Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | 2,400,000,000 | ||
Qualified Pension Plans [Member] | Georgia Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | 3,500,000,000 | ||
Qualified Pension Plans [Member] | Gulf Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | 0 | ||
Projected benefit obligations | 457,000,000 | ||
Qualified Pension Plans [Member] | Mississippi Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected postretirement trust contributions | 0 | ||
Projected benefit obligations | 470,000,000 | ||
Non Qualified Pension Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | 582,000,000 | ||
Non Qualified Pension Plans [Member] | Alabama Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | 124,000,000 | ||
Non Qualified Pension Plans [Member] | Georgia Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | 151,000,000 | ||
Non Qualified Pension Plans [Member] | Gulf Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | 23,000,000 | ||
Non Qualified Pension Plans [Member] | Mississippi Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligations | $ 30,000,000 |
Acquisitions - Textual (Details
Acquisitions - Textual (Details) | Feb. 24, 2016USD ($)$ / shares | Dec. 11, 2015USD ($)MW | Aug. 23, 2015USD ($)$ / shares | Feb. 24, 2015USD ($) | Nov. 26, 2014USD ($) | Nov. 06, 2014USD ($)MW | May. 22, 2014USD ($)MW | Apr. 17, 2014USD ($)MW | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($)MW | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Sep. 30, 2015USD ($)MW | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Feb. 11, 2016 | Oct. 22, 2015 | Aug. 31, 2015USD ($) | Apr. 15, 2015 |
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Construction in Progress, Gross | $ 9,082,000,000 | $ 7,792,000,000 | $ 9,082,000,000 | $ 7,792,000,000 | ||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 6,505,000,000 | 6,505,000,000 | ||||||||||||||||||||||
Revenues | 3,568,000,000 | $ 5,401,000,000 | $ 4,337,000,000 | $ 4,183,000,000 | 4,017,000,000 | $ 5,339,000,000 | $ 4,467,000,000 | $ 4,644,000,000 | 17,489,000,000 | 18,467,000,000 | $ 17,087,000,000 | |||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed | 4,000,000 | |||||||||||||||||||||||
Construction in Progress, Gross | 1,137,000,000 | 11,000,000 | 1,137,000,000 | 11,000,000 | ||||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 146 | 146 | ||||||||||||||||||||||
Life Output Of Plant | 25 years | |||||||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 10,000,000 | 10,000,000 | ||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 600,000,000 | 500,000,000 | 600,000,000 | 500,000,000 | $ 600,000,000 | |||||||||||||||||||
Total Cost Of Construction | 1,800,000,000 | |||||||||||||||||||||||
Revenues | 304,000,000 | $ 401,000,000 | $ 337,000,000 | $ 348,000,000 | $ 386,000,000 | $ 435,000,000 | $ 329,000,000 | $ 351,000,000 | 1,390,000,000 | $ 1,501,000,000 | $ 1,275,000,000 | |||||||||||||
Southern Power [Member] | Series of Individually Immaterial Business Acquisitions [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | 18,000,000 | |||||||||||||||||||||||
Southern Power [Member] | Adobe Solar LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | |||||||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 20 | |||||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 97,000,000 | $ 86,000,000 | ||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 84,000,000 | |||||||||||||||||||||||
Reimbursable Transmission Costs Receivable | 15,000,000 | |||||||||||||||||||||||
Purchased Power Agreement Intangible | 6,000,000 | |||||||||||||||||||||||
Business Combination, Bargain Purchase, Gain Recognized, Amount | 5,000,000 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent | $ 3,000,000 | |||||||||||||||||||||||
Southern Power [Member] | Macho Springs, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | |||||||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 50 | |||||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 117,000,000 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 128,000,000 | |||||||||||||||||||||||
Reimbursable Transmission Costs Receivable | 1,000,000 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets | $ 1,000,000 | |||||||||||||||||||||||
Southern Power [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 150 | |||||||||||||||||||||||
Life Output Of Plant | 25 years | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 505,000,000 | 505,000,000 | ||||||||||||||||||||||
Southern Power [Member] | First Solar [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 128,000,000 | 599,000,000 | ||||||||||||||||||||||
Southern Power [Member] | Decatur Parkway Solar Project, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 84 | 84 | ||||||||||||||||||||||
Life Output Of Plant | 25 years | |||||||||||||||||||||||
Estimated Cost | $ 169,000,000 | |||||||||||||||||||||||
Southern Power [Member] | Decatur County Solar Project, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 20 | 20 | ||||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||||||
Estimated Cost | $ 46,000,000 | |||||||||||||||||||||||
Southern Power [Member] | Kay Wind, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||||||
Construction in Progress, Gross | 481,000,000 | 481,000,000 | ||||||||||||||||||||||
Construction Payable | 8,000,000 | 8,000,000 | ||||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 481,000,000 | $ 481,000,000 | ||||||||||||||||||||||
Reimbursable Transmission Costs Receivable | 8,000,000 | 8,000,000 | ||||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 299 | |||||||||||||||||||||||
First Solar [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Payments to Acquire Businesses, Gross | 223,000,000 | |||||||||||||||||||||||
SG2 Holdings, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 593,000,000 | 6,000,000 | ||||||||||||||||||||||
SG2 Holdings, LLC [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 708,000,000 | 708,000,000 | ||||||||||||||||||||||
Reimbursable Transmission Costs Receivable | $ 20,000,000 | $ 20,000,000 | ||||||||||||||||||||||
Class A Membership Interest [Member] | Southern Power [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | ||||||||||||||||||||||
Percentage Of Entitled Cash Distributions | 51.00% | |||||||||||||||||||||||
Class B Membership Interest [Member] | First Solar [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | ||||||||||||||||||||||
Percentage Of Entitled Cash Distributions | 49.00% | |||||||||||||||||||||||
Turner Renewable Energy [Member] | Southern Power [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% | 10.00% | 10.00% | |||||||||||||||||||||
Minimum [Member] | Southern Power [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Estimated Cost | 260,000,000 | |||||||||||||||||||||||
Maximum [Member] | Southern Power [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Estimated Cost | $ 280,000,000 | |||||||||||||||||||||||
Bridge Agreement [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Acquisition Related Costs | $ 41,000,000 | |||||||||||||||||||||||
Scenario, Plan [Member] | Bridge Agreement [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Acquisition, Share Price | $ / shares | $ 66 | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 8,200,000,000 | |||||||||||||||||||||||
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | 8,000,000,000 | |||||||||||||||||||||||
Business Combination, Acquisition Related Costs | $ 200,000,000 | |||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 8,100,000,000 | 8,100,000,000 | ||||||||||||||||||||||
Scenario, Plan [Member] | Bridge Agreement [Member] | AGL Resources [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Early Termination Fee | 201,000,000 | 201,000,000 | ||||||||||||||||||||||
Early Termination Reimbursable Expenses | $ 5,000,000 | $ 5,000,000 | ||||||||||||||||||||||
Subsequent Event [Member] | Turner Renewable Energy [Member] | Southern Power [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% | |||||||||||||||||||||||
Subsequent Event [Member] | Scenario, Plan [Member] | PowerSecure International, Inc. [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Acquisition, Share Price | $ / shares | $ 18.75 | |||||||||||||||||||||||
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $ 431,000,000 |
Acquisitions - Acquisitions Tab
Acquisitions - Acquisitions Table (Details) $ in Millions | Feb. 11, 2016USD ($)MW | Dec. 17, 2015USD ($)MW | Dec. 11, 2015USD ($)MW | Nov. 23, 2015USD ($)MW | Oct. 22, 2015USD ($)MW | Sep. 04, 2015USD ($)MW | Aug. 31, 2015USD ($)MW | Aug. 28, 2015USD ($)MW | Apr. 30, 2015USD ($)MW | Apr. 15, 2015USD ($)MW | Feb. 24, 2015USD ($) | Nov. 26, 2014USD ($) | Nov. 06, 2014USD ($)MW | May. 22, 2014USD ($)MW | Apr. 17, 2014USD ($)MW | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($)MW | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Business Acquisition [Line Items] | ||||||||||||||||||||
Capital contributions from noncontrolling interests | $ 567 | $ 221 | ||||||||||||||||||
Construction in Progress, Gross | $ 9,082 | 9,082 | 7,792 | |||||||||||||||||
Other Assets, Noncurrent | 737 | 737 | 922 | |||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, after Year Five | 239 | 239 | ||||||||||||||||||
Life Output Of Plant | 25 years | |||||||||||||||||||
Amortization of Intangible Assets | 3 | 3 | $ 3 | |||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 10 | 10 | ||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 146 | |||||||||||||||||||
Capital contributions from noncontrolling interests | 567 | 221 | ||||||||||||||||||
Business Combination, Contingent Consideration, Liability | 36 | 36 | 8 | |||||||||||||||||
Total Cost Of Construction | 1,800 | |||||||||||||||||||
Construction in Progress, Gross | 1,137 | 1,137 | 11 | |||||||||||||||||
Other Assets, Noncurrent | 139 | 139 | $ 100 | |||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 17 | 17 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 17 | 17 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 17 | 17 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 17 | 17 | ||||||||||||||||||
Southern Power [Member] | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Capital contributions from noncontrolling interests | 227 | |||||||||||||||||||
Southern Power [Member] | RE Garland Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Southern Power [Member] | Adobe Solar LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 97 | $ 86 | ||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 20 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | $ 84 | |||||||||||||||||||
Reimbursable Transmission Costs Receivable | 15 | |||||||||||||||||||
Purchased Power Agreement Intangible | 6 | |||||||||||||||||||
Business Combination, Bargain Purchase, Gain Recognized, Amount | 5 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent | $ 3 | |||||||||||||||||||
Southern Power [Member] | Kay Wind, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 299 | |||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 481 | $ 481 | ||||||||||||||||||
Business Combination, Contingent Consideration, Liability | $ 35 | |||||||||||||||||||
Reimbursable Transmission Costs Receivable | 8 | 8 | ||||||||||||||||||
Construction in Progress, Gross | 481 | 481 | ||||||||||||||||||
Construction Payable | 8 | 8 | ||||||||||||||||||
Southern Power [Member] | Grant Wind, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | MW | 151 | |||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 258 | |||||||||||||||||||
Business Combination, Contingent Consideration, Liability | $ 24 | |||||||||||||||||||
Period Of Operation For Performance Testing And Production | 10 years | |||||||||||||||||||
Southern Power [Member] | Lost Hills Blackwell Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Life Output Of Plant | 29 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 73 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 33 | |||||||||||||||||||
Business Combination, Contingent Consideration, Liability | $ 3 | |||||||||||||||||||
Business Combination, Consideration Transferred | 107 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 105 | 105 | ||||||||||||||||||
Reimbursable Transmission Costs Receivable | 3 | 3 | ||||||||||||||||||
Construction Payable | 4 | 4 | ||||||||||||||||||
Southern Power [Member] | NS Solar Holdings, LLC (North Star) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, after Year Five | 18 | 18 | ||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Amortization of Intangible Assets | 1 | |||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 1.2 | 1.2 | ||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 208 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 61 | |||||||||||||||||||
Business Combination, Contingent Consideration, Liability | $ 233 | |||||||||||||||||||
Business Combination, Consideration Transferred | 307 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 266 | 266 | ||||||||||||||||||
Reimbursable Transmission Costs Receivable | 21 | 21 | ||||||||||||||||||
Purchased Power Agreement Intangible | 25 | 25 | ||||||||||||||||||
Construction Payable | 238 | 238 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 1.2 | 1.2 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 1.2 | 1.2 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 1.2 | 1.2 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 1.2 | 1.2 | ||||||||||||||||||
Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Life Output Of Plant | 18 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 100 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 205 | |||||||||||||||||||
Construction in Progress, Gross | $ 186 | |||||||||||||||||||
Other Receivables | 24 | |||||||||||||||||||
Construction Payable | 37 | |||||||||||||||||||
Southern Power [Member] | Desert Stateline Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, after Year Five | 192.8 | 192.8 | ||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 6.2 | 6.2 | ||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 439 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 299 | |||||||||||||||||||
Purchased Power Agreement Intangible | $ 249 | |||||||||||||||||||
Construction in Progress, Gross | 413 | |||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 12.5 | 12.5 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 12.5 | 12.5 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 12.5 | 12.5 | ||||||||||||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 12.5 | 12.5 | ||||||||||||||||||
Southern Power [Member] | GASNA 31P, LLC (Morelos) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 45 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 15 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 49 | 49 | ||||||||||||||||||
Reimbursable Transmission Costs Receivable | 1 | 1 | ||||||||||||||||||
Southern Power [Member] | RE Roserock Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 45 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 160 | |||||||||||||||||||
Construction in Progress, Gross | 75 | 75 | ||||||||||||||||||
Other Receivables | 6 | 6 | ||||||||||||||||||
Construction Payable | 10 | 10 | ||||||||||||||||||
Southern Power [Member] | RE Roserock Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Life Output Of Plant | 15 years | |||||||||||||||||||
Southern Power [Member] | Macho Springs, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 117 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 50 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | $ 128 | |||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets | 1 | |||||||||||||||||||
Reimbursable Transmission Costs Receivable | 1 | |||||||||||||||||||
Business Combination, Consideration Transferred, Including Equity Interest in Acquiree Held Prior to Combination | $ 130 | |||||||||||||||||||
Southern Power [Member] | First Solar [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 128 | 599 | ||||||||||||||||||
Southern Power [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Life Output Of Plant | 25 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 505 | 505 | ||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 150 | |||||||||||||||||||
Southern Power [Member] | RE Garland Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 49 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 205 | |||||||||||||||||||
Construction in Progress, Gross | 107 | 107 | ||||||||||||||||||
Other Assets, Noncurrent | 1 | 1 | ||||||||||||||||||
Construction Payable | 28 | 28 | ||||||||||||||||||
Southern Power [Member] | Decatur Parkway Solar Project, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Life Output Of Plant | 25 years | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 84 | |||||||||||||||||||
Estimated Cost | $ 169 | |||||||||||||||||||
Southern Power [Member] | Decatur County Solar Project, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 20 | |||||||||||||||||||
Estimated Cost | $ 46 | |||||||||||||||||||
Southern Power [Member] | Butler Solar Farm, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 22 | |||||||||||||||||||
Estimated Cost | $ 45 | |||||||||||||||||||
SG2 Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 593 | 6 | ||||||||||||||||||
SG2 Holdings, LLC [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 708 | 708 | ||||||||||||||||||
Reimbursable Transmission Costs Receivable | 20 | 20 | ||||||||||||||||||
Southern Power and Turner Renewable Energy [Member] | GASNA 31P, LLC (Morelos) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 50 | |||||||||||||||||||
Recurrent Energy [Member] | RE Tranquility Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Contribution of Assets | 173 | |||||||||||||||||||
Initial Distribution Received | $ 100 | |||||||||||||||||||
Estimated Future Construction Payments | 493 | $ 493 | ||||||||||||||||||
Recurrent Energy [Member] | RE Roserock Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Contribution of Assets | $ 26 | |||||||||||||||||||
Recurrent Energy [Member] | RE Garland Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Contribution of Assets | $ 31 | |||||||||||||||||||
First Solar [Member] | Lost Hills Blackwell Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 34 | |||||||||||||||||||
First Solar [Member] | NS Solar Holdings, LLC (North Star) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 99 | |||||||||||||||||||
First Solar [Member] | Desert Stateline Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 223 | |||||||||||||||||||
First Solar [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 223 | |||||||||||||||||||
Class A Membership Interest [Member] | Southern Power [Member] | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | ||||||||||||||||||
Percentage Of Entitled Cash Distributions | 51.00% | 51.00% | ||||||||||||||||||
Class A Membership Interest [Member] | Southern Power [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | ||||||||||||||||||
Percentage Of Entitled Cash Distributions | 51.00% | |||||||||||||||||||
Class B Membership Interest [Member] | First Solar and Recurrent Energy [Member] | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | ||||||||||||||||||
Class B Membership Interest [Member] | Recurrent Energy [Member] | RE Tranquility Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Class B Membership Interest [Member] | Recurrent Energy [Member] | RE Roserock Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Class B Membership Interest [Member] | Recurrent Energy [Member] | RE Garland Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Class B Membership Interest [Member] | First Solar [Member] | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Percentage Of Entitled Cash Distributions | 49.00% | 49.00% | ||||||||||||||||||
Class B Membership Interest [Member] | First Solar [Member] | Lost Hills Blackwell Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Class B Membership Interest [Member] | First Solar [Member] | NS Solar Holdings, LLC (North Star) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Class B Membership Interest [Member] | First Solar [Member] | Desert Stateline Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | |||||||||||||||||||
Class B Membership Interest [Member] | First Solar [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | ||||||||||||||||||
Percentage Of Entitled Cash Distributions | 49.00% | |||||||||||||||||||
Minimum [Member] | Southern Power [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Cost | 260 | |||||||||||||||||||
Minimum [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | $ 473 | $ 473 | ||||||||||||||||||
Minimum [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | 333 | 333 | ||||||||||||||||||
Minimum [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | 532 | 532 | ||||||||||||||||||
Minimum [Member] | Southern Power and First Solar [Member] | Desert Stateline Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | 1,200 | 1,200 | ||||||||||||||||||
Maximum [Member] | Southern Power [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Cost | $ 280 | |||||||||||||||||||
Maximum [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | 353 | 353 | ||||||||||||||||||
Maximum [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | 552 | 552 | ||||||||||||||||||
Maximum [Member] | Southern Power and First Solar [Member] | Desert Stateline Holdings, LLC [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Estimated Future Construction Payments | $ 1,300 | $ 1,300 | ||||||||||||||||||
Turner Renewable Energy [Member] | Southern Power [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% | 10.00% | 10.00% | |||||||||||||||||
Subsequent Event [Member] | Southern Power [Member] | 70SM1 8ME, LCC (Calipatria) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | |||||||||||||||||||
Life Output Of Plant | 20 years | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 52 | |||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | MW | 20 | |||||||||||||||||||
Subsequent Event [Member] | Southern Power and Turner Renewable Energy [Member] | 70SM1 8ME, LCC (Calipatria) [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 58 | |||||||||||||||||||
Subsequent Event [Member] | Turner Renewable Energy [Member] | Southern Power [Member] | ||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% |
Acquisitions - Construction Pro
Acquisitions - Construction Projects (Details) - Southern Power [Member] $ in Millions | 9 Months Ended |
Sep. 30, 2015USD ($)MW | |
Business Acquisition [Line Items] | |
Power of Solar Polycrystalline Silicon Facility | MW | 146 |
Life Output Of Plant | 25 years |
Decatur Parkway Solar Project, LLC [Member] | |
Business Acquisition [Line Items] | |
Power of Solar Polycrystalline Silicon Facility | MW | 84 |
Life Output Of Plant | 25 years |
Estimated Cost | $ 169 |
Decatur County Solar Project, LLC [Member] | |
Business Acquisition [Line Items] | |
Power of Solar Polycrystalline Silicon Facility | MW | 20 |
Life Output Of Plant | 20 years |
Estimated Cost | $ 46 |
Butler Solar LLC [Member] | |
Business Acquisition [Line Items] | |
Power of Solar Polycrystalline Silicon Facility | MW | 103 |
Life Output Of Plant | 30 years |
LS Pawpaw, LLC [Member] | |
Business Acquisition [Line Items] | |
Power of Solar Polycrystalline Silicon Facility | MW | 30 |
Life Output Of Plant | 30 years |
Butler Solar Farm, LLC [Member] | |
Business Acquisition [Line Items] | |
Power of Solar Polycrystalline Silicon Facility | MW | 22 |
Life Output Of Plant | 20 years |
Estimated Cost | $ 45 |
Maximum [Member] | |
Business Acquisition [Line Items] | |
Estimated Cost | 280 |
Maximum [Member] | Butler Solar LLC [Member] | |
Business Acquisition [Line Items] | |
Estimated Cost | 230 |
Maximum [Member] | LS Pawpaw, LLC [Member] | |
Business Acquisition [Line Items] | |
Estimated Cost | 80 |
Minimum [Member] | |
Business Acquisition [Line Items] | |
Estimated Cost | 260 |
Minimum [Member] | Butler Solar LLC [Member] | |
Business Acquisition [Line Items] | |
Estimated Cost | 220 |
Minimum [Member] | LS Pawpaw, LLC [Member] | |
Business Acquisition [Line Items] | |
Estimated Cost | $ 70 |
Contingencies and Regulatory 67
Contingencies and Regulatory Matters - Current And Actual Cost Estimate (Details) - Mississippi Power [Member] - USD ($) $ in Millions | Apr. 01, 2015 | Jan. 31, 2013 | Dec. 31, 2015 | Oct. 06, 2014 |
Loss Contingencies [Line Items] | ||||
AFUDC Cost | $ 14 | $ 36 | ||
Total Kemper IGCC | $ 2,880 | |||
Loss Contingency, Estimate of Possible Loss | 2,410 | |||
Electricity Generation Plant, Non-Nuclear [Member] | ||||
Loss Contingencies [Line Items] | ||||
Plant Subject to Cost Cap | $ 2,440 | |||
Kemper IGCC [Member] | ||||
Loss Contingencies [Line Items] | ||||
Plant Subject to Cost Cap | 4,830 | |||
Cost Of Lignite Mine And Equipment | 230 | |||
Cost Of CO2 Pipeline Facilities | 110 | |||
Cost Of AFUDC | 590 | |||
Combined Cycle And Related Assets Placed In Service, Incremental | 10 | |||
AFUDC Cost | $ 11 | |||
Plant General Exceptions | 90 | |||
Plant Regulatory Asset | 170 | |||
Total Kemper IGCC | $ 6,030 | |||
Purchase of Interest | 100.00% | 15.00% | ||
Kemper IGCC [Member] | Project Estimate [Member] | ||||
Loss Contingencies [Line Items] | ||||
Plant Subject to Cost Cap | $ 2,400 | |||
Cost Of Lignite Mine And Equipment | 210 | |||
Cost Of CO2 Pipeline Facilities | 140 | |||
Cost Of AFUDC | 170 | |||
Combined Cycle And Related Assets Placed In Service, Incremental | 0 | |||
Plant General Exceptions | 50 | |||
Plant Regulatory Asset | 0 | |||
Total Kemper IGCC | 2,970 | |||
Kemper IGCC [Member] | Current Estimate [Member] | ||||
Loss Contingencies [Line Items] | ||||
Plant Subject to Cost Cap | 5,290 | |||
Cost Of Lignite Mine And Equipment | 230 | |||
Cost Of CO2 Pipeline Facilities | 110 | |||
Cost Of AFUDC | 690 | |||
Combined Cycle And Related Assets Placed In Service, Incremental | 10 | |||
Plant General Exceptions | 100 | |||
Plant Regulatory Asset | 200 | |||
Total Kemper IGCC | $ 6,630 |
Contingencies and Regulatory 68
Contingencies and Regulatory Matters - Textual (Details) | Jan. 29, 2016MW | Jan. 01, 2016USD ($)$ / KWH_Kilowatt_hour | Dec. 03, 2015USD ($) | Apr. 16, 2015MW | Apr. 15, 2015USD ($) | Apr. 01, 2015USD ($) | Mar. 19, 2015USD ($) | Jan. 01, 2014USD ($) | Apr. 01, 2013USD ($) | Mar. 19, 2013 | Apr. 01, 2012USD ($) | Dec. 31, 2015USD ($)lawsuitmi | Nov. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Apr. 30, 2015MW | May. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jul. 31, 2013CustomerMW | Feb. 28, 2013USD ($) | Jan. 31, 2013USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($)lawsuitmi | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)lawsuitmi | Sep. 30, 2016MW | Sep. 30, 2015USD ($) | Dec. 31, 2019 | Dec. 31, 2018$ / KWH_Kilowatt_hour | Dec. 31, 2017$ / KWH_Kilowatt_hour | Dec. 31, 2015USD ($)lawsuitmi$ / KWH_Kilowatt_hourMW | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2010 | Dec. 31, 2008MW | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($)lawsuitmi | Dec. 31, 2017 | Dec. 31, 2015USD ($)lawsuitmi | Dec. 31, 2019 | Dec. 31, 2016USD ($) | Feb. 26, 2016USD ($) | Feb. 01, 2016USD ($) | Jan. 13, 2016USD ($) | Dec. 15, 2015USD ($) | Dec. 01, 2015USD ($) | Nov. 02, 2015USD ($) | Oct. 23, 2015lawsuit | Oct. 06, 2015USD ($) | Sep. 01, 2015USD ($) | Aug. 13, 2015USD ($) | Jul. 10, 2015USD ($) | Jun. 03, 2015USD ($) | May. 20, 2015USD ($) | Feb. 19, 2015USD ($) | Feb. 01, 2015 | Dec. 01, 2014USD ($) | Oct. 20, 2014USD ($) | Oct. 06, 2014 | Aug. 05, 2014USD ($) | Aug. 01, 2014MW | Jul. 01, 2014MW | Aug. 31, 2013USD ($) | May. 31, 2013USD ($) | Mar. 31, 2013USD ($) | Jan. 01, 2013USD ($) | Dec. 31, 2012USD ($) | Jun. 01, 2012USD ($) | Jan. 01, 2012USD ($) | Jan. 01, 2011USD ($) |
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | $ 402,000,000 | $ 346,000,000 | $ 402,000,000 | $ 346,000,000 | $ 402,000,000 | $ 402,000,000 | $ 346,000,000 | $ 346,000,000 | $ 402,000,000 | $ 402,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 3,759,000,000 | $ 2,018,000,000 | 2,201,000,000 | 3,759,000,000 | 2,201,000,000 | 3,759,000,000 | 3,759,000,000 | 2,201,000,000 | $ 2,018,000,000 | 2,201,000,000 | 3,759,000,000 | 3,759,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 433,000,000 | 7,000,000 | 170,000,000 | 433,000,000 | 170,000,000 | 433,000,000 | 433,000,000 | 170,000,000 | 7,000,000 | 170,000,000 | 433,000,000 | 433,000,000 | $ 70,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest-bearing refundable deposits | 0 | 275,000,000 | 0 | 275,000,000 | 0 | 0 | 275,000,000 | 275,000,000 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 1,162,000,000 | 1,215,000,000 | 1,162,000,000 | 1,215,000,000 | 1,162,000,000 | 1,162,000,000 | 1,215,000,000 | 1,215,000,000 | 1,162,000,000 | 1,162,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 4,989,000,000 | 4,334,000,000 | 4,989,000,000 | 4,334,000,000 | 4,989,000,000 | 4,989,000,000 | 4,334,000,000 | 4,334,000,000 | 4,989,000,000 | 4,989,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 6,505,000,000 | 6,505,000,000 | 6,505,000,000 | 6,505,000,000 | 6,505,000,000 | 6,505,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction in Progress, Gross | $ 9,082,000,000 | 7,792,000,000 | 9,082,000,000 | 7,792,000,000 | $ 9,082,000,000 | 9,082,000,000 | 7,792,000,000 | 7,792,000,000 | $ 9,082,000,000 | $ 9,082,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax Charge To Income | 183,000,000 | $ 150,000,000 | $ 23,000,000 | $ 9,000,000 | 70,000,000 | $ 418,000,000 | $ 380,000,000 | 365,000,000 | 868,000,000 | 1,200,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
After Tax Charge To Income | $ 113,000,000 | 93,000,000 | 14,000,000 | 6,000,000 | 43,000,000 | $ 258,000,000 | 235,000,000 | $ 226,000,000 | 536,000,000 | 729,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Parent And Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax Charge To Income | 1,200,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
After Tax Charge To Income | 729,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AGL Resources [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Class Action Lawsuits | lawsuit | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Parent Company and Merger Sub [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Class Action Lawsuits | lawsuit | 2 | 2 | 2 | 2 | 2 | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power and Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost of Project One | $ 653,000,000 | $ 653,000,000 | $ 653,000,000 | $ 653,000,000 | $ 653,000,000 | $ 653,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Designated Customer Value Benchmark Survey | 33.30% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Fuel Disposal Costs [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Claims awarded to companies related to nuclear fuel disposal litigation | $ 26,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate Adjustment Period | 2 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum percentage of Rate RSE | 4.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum annual percentage of ratio rate | 5.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate RSE Increase | 3.49% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate RSE Increase Amount | $ 181,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Adjusting Point Of Weighted Cost Of Equity | 5.98% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Basis Points | 0.07% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered certified PPA balance | 99,000,000 | 99,000,000 | 99,000,000 | $ 99,000,000 | 99,000,000 | 99,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Rate Cnp Balance | $ 75,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered environmental clause | 43,000,000 | 43,000,000 | 43,000,000 | $ 43,000,000 | 43,000,000 | 43,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of Regulatory Asset | 123,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liability Amortization | 120,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved billing rate under rate ECR up to (cents per KWH) | $ / KWH_Kilowatt_hour | 0.02030 | 0.05910 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate ECR Increase Decrease | 6.70% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate ECR Increase Decrease Amount | $ 370,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Future stated rates under rate Ecr factor in terms of per units | $ / KWH_Kilowatt_hour | 0.02681 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 238,000,000 | 47,000,000 | 238,000,000 | 47,000,000 | 238,000,000 | $ 238,000,000 | 47,000,000 | 47,000,000 | 238,000,000 | 238,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred over recovered regulatory clause revenues | 0 | 47,000,000 | 0 | 47,000,000 | 0 | $ 0 | 47,000,000 | 47,000,000 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Period for recovery deferred storm-related operations and maintenance costs and any future reserve deficit | 24 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum total rate NDR charge per month, non-residential customer account | 10 | 10 | 10 | $ 10 | 10 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum total rate NDR charge per month, residential customer account | 5 | 5 | 5 | 5 | 5 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Old Natural Disaster Reserve Authorized Limit | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Under Recovered Rate CNP Balance | 1.50% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferral of maintenance costs | 50,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | $ 115,000,000 | 84,000,000 | $ 115,000,000 | 84,000,000 | $ 115,000,000 | $ 115,000,000 | 84,000,000 | 84,000,000 | $ 115,000,000 | $ 115,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 14.00% | 14.00% | 14.00% | 14.00% | 14.00% | 14.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | $ 1,448,000,000 | 730,000,000 | 829,000,000 | $ 1,448,000,000 | 829,000,000 | $ 1,448,000,000 | $ 1,448,000,000 | 829,000,000 | 730,000,000 | 829,000,000 | $ 1,448,000,000 | $ 1,448,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 722,000,000 | 744,000,000 | 722,000,000 | 744,000,000 | 722,000,000 | 722,000,000 | 744,000,000 | 744,000,000 | 722,000,000 | 722,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-nuclear Outage Costs | 95,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Compliance And Pension Costs | 28,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 1,114,000,000 | 1,063,000,000 | 1,114,000,000 | 1,063,000,000 | 1,114,000,000 | 1,114,000,000 | 1,063,000,000 | 1,063,000,000 | 1,114,000,000 | 1,114,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,340,000,000 | 1,340,000,000 | 1,340,000,000 | 1,340,000,000 | 1,340,000,000 | 1,340,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction in Progress, Gross | $ 801,000,000 | 1,006,000,000 | $ 801,000,000 | 1,006,000,000 | $ 801,000,000 | $ 801,000,000 | 1,006,000,000 | 1,006,000,000 | $ 801,000,000 | $ 801,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Scenario, Forecast [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Future stated rates under rate Ecr factor in terms of per units | $ / KWH_Kilowatt_hour | 0.05910 | 0.02681 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted Cost Of Equity | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted Cost Of Equity | 6.21% | 6.21% | 6.21% | 6.21% | 6.21% | 6.21% | 6.21% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Fuel Recovery Clause [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred over recovered regulatory clause revenues | $ 238,000,000 | $ 238,000,000 | $ 238,000,000 | $ 238,000,000 | $ 238,000,000 | $ 238,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Gorgas Units 6 and 7 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 200 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Greene County Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 300 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Barry Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 250 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Barry Unit 3 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 225 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Farley [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Recovery Amount From Customers Associated With Permanent Disposal Of Nuclear Waste | 20,000,000 | 20,000,000 | 20,000,000 | $ 20,000,000 | 20,000,000 | 20,000,000 | $ 14,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase In NCCR Tariff | $ 60,000,000 | $ 27,000,000 | $ 50,000,000 | $ 35,000,000 | $ 223,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 29,000,000 | 29,000,000 | 29,000,000 | $ 29,000,000 | 29,000,000 | 29,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Fuel Disposal Costs [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Claims awarded to companies related to nuclear fuel disposal litigation | $ 18,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Portion of Actual Earnings Above Approved ROE Band Retained by Subsidiary Company | 33.33333% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Portion of Actual Earnings Above Approved ROE Band Refunded to Customers | 66.66667% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liability Amortization | $ 14,000,000 | 14,000,000 | 31,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 10.95% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period for Environmental Construction | 9 years | 9 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 123,000,000 | 136,000,000 | 123,000,000 | 136,000,000 | 123,000,000 | $ 123,000,000 | 136,000,000 | 136,000,000 | 123,000,000 | 123,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | 4,400,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amendment To Estimated In-service Capital Cost | 4,800,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue Subject To Refund | 11,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 1,916,000,000 | 1,222,000,000 | 1,255,000,000 | 1,916,000,000 | 1,255,000,000 | 1,916,000,000 | 1,916,000,000 | 1,255,000,000 | 1,222,000,000 | 1,255,000,000 | 1,916,000,000 | 1,916,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 3,000,000 | $ 0 | 0 | 3,000,000 | 0 | 3,000,000 | 3,000,000 | 0 | 0 | 0 | 3,000,000 | 3,000,000 | 23,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 16,000,000 | 46,000,000 | 16,000,000 | 46,000,000 | 16,000,000 | 16,000,000 | 46,000,000 | 46,000,000 | 16,000,000 | 16,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number Of Intervenors Approved ARP | 11 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Intervenors | 13 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) in Base Tariff Rate | $ 80,000,000 | $ 49,000,000 | $ 107,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) In ECCR Tariff | 25,000,000 | 75,000,000 | 23,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) In Demand Side Management Tariff | 1,000,000 | 3,000,000 | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) In Municipal Franchise Fee Tariff | 4,000,000 | 13,000,000 | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) in Revenue to be Received from Base Rate Change | $ 110,000,000 | 140,000,000 | $ 136,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved Increase in Annual Billing Based on Fuel Cost Recovery Rate | $ 350,000,000 | $ 122,000,000 | $ 567,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 116,000,000 | 199,000,000 | 116,000,000 | 199,000,000 | 116,000,000 | $ 116,000,000 | 199,000,000 | 199,000,000 | 116,000,000 | 116,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrual Under Alternate Rate Plan | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 2,152,000,000 | 1,753,000,000 | 2,152,000,000 | 1,753,000,000 | 2,152,000,000 | 2,152,000,000 | 1,753,000,000 | 1,753,000,000 | 2,152,000,000 | 2,152,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Capacity in Mega Watts Under Consortium Agreement | MW | 1,100 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Construction Capital Costs | 5,440,000,000 | $ 160,000,000 | 3,100,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Delay Of Estimated In-service Date | 18 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of Proportionate Share Owed in Consortium Agreement | 45.70% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,750,000,000 | 1,750,000,000 | 1,750,000,000 | $ 1,750,000,000 | 1,750,000,000 | 1,750,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) In Projected Certified Construction Capital Costs | 5.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction in Progress, Gross | $ 4,775,000,000 | 4,031,000,000 | $ 4,775,000,000 | 4,031,000,000 | $ 4,775,000,000 | $ 4,775,000,000 | 4,031,000,000 | 4,031,000,000 | $ 4,775,000,000 | $ 4,775,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase In NCCR Tariff | $ 19,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included in Application Request By Subsidiaries For Future Period Requests | MW | 525 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Intercession City Combustion Turbine [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 33.30% | 33.30% | 33.30% | 33.30% | 33.30% | 33.30% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Intercession City Combustion Turbine [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request To Sell | MW | 143 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | $ 4,400,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 12.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Construction Capital Costs | $ 114,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Property damage reserves-liability [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | $ 30,000,000 | 30,000,000 | $ 30,000,000 | 30,000,000 | $ 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | $ 30,000,000 | $ 30,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 62,000,000 | 68,000,000 | 62,000,000 | 68,000,000 | 62,000,000 | 62,000,000 | 68,000,000 | 68,000,000 | 62,000,000 | 62,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory asset | 92,000,000 | 98,000,000 | 92,000,000 | 98,000,000 | 92,000,000 | 92,000,000 | 98,000,000 | 98,000,000 | 92,000,000 | 92,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Storm Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory asset | 92,000,000 | 98,000,000 | 92,000,000 | 98,000,000 | 92,000,000 | 92,000,000 | 98,000,000 | 98,000,000 | 92,000,000 | 92,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Branch Units 1 and 3 and 4 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 1,266 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | 5,000,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Operational Readiness Costs | 10,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Financing Costs | 27,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction Financing Costs | $ 2,400,000,000 | 2,400,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction in Progress, Gross | 3,600,000,000 | 3,600,000,000 | 3,600,000,000 | 3,600,000,000 | 3,600,000,000 | 3,600,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Yates [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | MW | 579 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant McManus [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | MW | 122 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Kraft [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | MW | 316 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Mitchell Units 3, 4A, and 4B [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 217 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Kraft Unit 1 [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | MW | 17 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Mitchell [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Small Power Production Facility | MW | 155 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
FERC Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Annual Base Wholesale Revenues | $ 23,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Over Which Annual Revenue Will Increase Under Tariff | 12 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Base Rate Under Cost Based Electric Tariff Due to Settlement | $ 24,000,000 | $ 10,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Anticipates of elimination adjustment will result in additional revenues | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSC Approved Annual Property Damage Reserve Accrual | $ 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual PEP Lookback Refund To Customers | $ 5,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 3,000,000 | 3,000,000 | 3,000,000 | 3,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 95,000,000 | 73,000,000 | 95,000,000 | 73,000,000 | 95,000,000 | 95,000,000 | 73,000,000 | 73,000,000 | 95,000,000 | 95,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 3,470,000,000 | 3,470,000,000 | 3,470,000,000 | 3,470,000,000 | 3,470,000,000 | 3,470,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Required Customers For Energy Efficiency Programs | Customer | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Required Period For Filing Quick Start Plans | 6 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Of PSC Retail Rate Increase | 0.35% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project expenditures, cumulative | 637,000,000 | 637,000,000 | 637,000,000 | 637,000,000 | 637,000,000 | 637,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project expenditures, cumulative, proportionate share | 325,000,000 | 325,000,000 | 325,000,000 | 325,000,000 | 325,000,000 | 325,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AFUDC Cost | $ 14,000,000 | 36,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSC Retail Rate Increase | $ 2,000,000 | $ 7,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
System Restoration Rider Rate | 0.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | $ 2,000,000 | $ 2,000,000 | $ 2,000,000 | $ 2,000,000 | $ 2,000,000 | $ 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Plant capacity under coal gasification combined cycle technology in Mega Watts | MW | 582 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
New Co2 Pipeline Infrastructure | mi | 61 | 61 | 61 | 61 | 61 | 61 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs Related to Grant Funding | $ 245,000,000 | 245,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum cap construction cost | $ 2,880,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate Recovery | $ 371,000,000 | $ 342,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Carrying Costs Associated With Retail Rate Recovery | $ 29,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | $ 3,470,000,000 | $ 3,470,000,000 | $ 3,470,000,000 | 3,470,000,000 | 3,470,000,000 | 3,470,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingency, Estimate of Possible Loss | 2,410,000,000 | 2,410,000,000 | 2,410,000,000 | 2,410,000,000 | 2,410,000,000 | 2,410,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Property And Investments | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prepaid Supplies | 45,000,000 | 45,000,000 | 45,000,000 | 45,000,000 | 45,000,000 | 45,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost deferred in other regulatory assets | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other deferred charges and assets | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 177,000,000 | 42,000,000 | 48,000,000 | 177,000,000 | 48,000,000 | 177,000,000 | 177,000,000 | 48,000,000 | 42,000,000 | 48,000,000 | 177,000,000 | 177,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lignite Mining Costs | 69,000,000 | 69,000,000 | 69,000,000 | 69,000,000 | 69,000,000 | 69,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase Retail Rates In Year One | 15.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase Retail Rates In Year Two | 3.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement Collection Amount To Mitigate Rate Impact Year Two | $ 156,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | $ 421,000,000 | 4,000,000 | 165,000,000 | $ 421,000,000 | 165,000,000 | $ 421,000,000 | $ 421,000,000 | 165,000,000 | $ 4,000,000 | 165,000,000 | $ 421,000,000 | $ 421,000,000 | $ 6,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reduced Percentage Interest Transferred under Asset Purchase Agreement | 15.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of management fee contract | 40 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of Carbon dioxide captured from project by purchase Denbury | 70.00% | 70.00% | 70.00% | 70.00% | 70.00% | 70.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of contract to purchase carbon dioxide from Kemper IGCC | 30.00% | 30.00% | 30.00% | 30.00% | 30.00% | 30.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest-bearing refundable deposits | $ 0 | 275,000,000 | $ 0 | 275,000,000 | $ 0 | $ 0 | 275,000,000 | 275,000,000 | $ 0 | $ 0 | $ 275,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Return Of Interest Bearing Refundable Deposits Related to Assets Sale Plus Accrued Interest | 301,000,000 | $ 375,000,000 | 301,000,000 | 0 | $ 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tax credits (Phase II) | $ 279,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum percentage of carbon dioxide that must be capture and sequester to remain eligible for the phase II tax credits | 65.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Of Bonus Depreciation Extension | 5 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual PEP Filing Rate Increase | 1.90% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual PEP Filing Rate Increase Amount | $ 15,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.13% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 165,000,000 | 166,000,000 | 165,000,000 | 166,000,000 | 165,000,000 | $ 165,000,000 | 166,000,000 | 166,000,000 | 165,000,000 | 165,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 525,000,000 | 385,000,000 | 525,000,000 | 385,000,000 | 525,000,000 | 525,000,000 | 385,000,000 | 385,000,000 | 525,000,000 | 525,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 220,000,000 | 220,000,000 | 220,000,000 | 220,000,000 | 220,000,000 | 220,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction in Progress, Gross | $ 2,254,000,000 | $ 2,161,000,000 | $ 2,254,000,000 | 2,161,000,000 | $ 2,254,000,000 | $ 2,254,000,000 | 2,161,000,000 | $ 2,161,000,000 | $ 2,254,000,000 | $ 2,254,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proposed Change in Annual Revenues | $ 47,000,000 | $ 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Of Bonus Depreciation Extension | 5 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Bonus Depreciation for Property Acquired | 30.00% | 40.00% | 50.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Daniel Units 1 and 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period For Quick Start Plans To Be In Effect | 2 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period For Quick Start Plans To Be In Effect | 3 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Retail [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proposed Change in Annual Revenues | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Fuel Cost | 71,000,000 | 71,000,000 | 71,000,000 | 71,000,000 | 71,000,000 | 71,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | MRA Revenue [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | $ 24,000,000 | $ 24,000,000 | $ 24,000,000 | $ 24,000,000 | $ 24,000,000 | $ 24,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Gulf Power [Member] | Plant Daniel Units 1 and 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Electricity Generation Plant, Non-Nuclear [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost | $ 2,440,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alternate Financing | $ 1,000,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | $ 96,000,000 | $ 96,000,000 | $ 96,000,000 | $ 96,000,000 | $ 96,000,000 | $ 96,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AFUDC Cost | $ 11,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost | 4,830,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum cap construction cost | 6,030,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Charge Of Allowance For Equity Funds Used During Construction | 13,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Cost, Regulatory Assets and Other | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax Charge To Income | 183,000,000 | 150,000,000 | 23,000,000 | 9,000,000 | 70,000,000 | $ 418,000,000 | 380,000,000 | 365,000,000 | 868,000,000 | 1,100,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
After Tax Charge To Income | 113,000,000 | $ 93,000,000 | $ 14,000,000 | $ 6,000,000 | $ 43,000,000 | $ 258,000,000 | $ 235,000,000 | 226,000,000 | $ 536,000,000 | 681,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | $ 423,000,000 | $ 423,000,000 | $ 423,000,000 | $ 423,000,000 | $ 423,000,000 | $ 423,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase of interest in plant | 100.00% | 100.00% | 100.00% | 100.00% | 100.00% | 100.00% | 15.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Positive Impact From Bonus Depreciation | $ 3,000,000 | $ 3,000,000 | $ 3,000,000 | $ 3,000,000 | $ 3,000,000 | $ 3,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 195,000,000 | 195,000,000 | 195,000,000 | 195,000,000 | 195,000,000 | 195,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory asset | 120,000,000 | 120,000,000 | 120,000,000 | 120,000,000 | 120,000,000 | 120,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Positive Impact From Bonus Depreciation | $ 360,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | $ 25,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization Period of Regulatory Assets and Liabilities | 2 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | $ 35,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization Period of Regulatory Assets and Liabilities | 10 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Mine [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of management fee contract | 40 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Sweatt Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Unit Conversion To Non-fossil Fuel Source | MW | 80 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Watson Units 4 And 5 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Unit Conversion To Non-fossil Fuel Source | MW | 750 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Greene County Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 5,000,000 | 5,000,000 | 5,000,000 | $ 5,000,000 | 5,000,000 | 5,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Unit Conversion To Non-fossil Fuel Source | MW | 200 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 5,000,000 | 5,000,000 | 5,000,000 | 5,000,000 | 5,000,000 | 5,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Watson [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 46,000,000 | 46,000,000 | 46,000,000 | 46,000,000 | 46,000,000 | 46,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSC Approved Annual Property Damage Reserve Accrual | $ 3,500,000 | $ 3,500,000 | $ 3,500,000 | $ 3,500,000 | $ 3,500,000 | $ 3,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Of Treasury Yield Rate | 30 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Basis Points | 0.25% | 0.25% | 0.25% | 0.25% | 0.25% | 0.25% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 10.25% | 10.25% | 10.25% | 10.25% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | $ 90,000,000 | $ 74,000,000 | $ 90,000,000 | $ 74,000,000 | $ 90,000,000 | $ 90,000,000 | $ 74,000,000 | $ 74,000,000 | $ 90,000,000 | $ 90,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 130,000,000 | $ 16,000,000 | 17,000,000 | 130,000,000 | 17,000,000 | 130,000,000 | 130,000,000 | 17,000,000 | $ 16,000,000 | 17,000,000 | 130,000,000 | 130,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost of Project One | 316,000,000 | 316,000,000 | 316,000,000 | $ 316,000,000 | 316,000,000 | 316,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Base Revenue In Year One | 35,000,000 | 35,000,000 | 35,000,000 | 35,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Base Revenue In Year Two | 20,000,000 | 20,000,000 | 20,000,000 | 20,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period of Treasury Rate Above Basis Points | 6 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 233,000,000 | 235,000,000 | 233,000,000 | 235,000,000 | 233,000,000 | $ 233,000,000 | 235,000,000 | 235,000,000 | 233,000,000 | 233,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reduction In Depreciation Expense | $ 8,400,000 | 20,100,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate Increase (Decrease) | $ 49,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Power Over (Under) Recovered Balance Percentage | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period of Establishment of Conservation Goals, in Years | 5 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Numeric Conservation Goals Cover, in Years | 10 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 427,000,000 | 416,000,000 | 427,000,000 | 416,000,000 | 427,000,000 | $ 427,000,000 | 416,000,000 | 416,000,000 | 427,000,000 | 427,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 275,000,000 | 275,000,000 | 275,000,000 | 275,000,000 | 275,000,000 | 275,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction in Progress, Gross | $ 48,000,000 | $ 465,000,000 | $ 48,000,000 | $ 465,000,000 | $ 48,000,000 | $ 48,000,000 | $ 465,000,000 | $ 465,000,000 | $ 48,000,000 | $ 48,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | Plant Daniel Units 1 and 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Basis Points | 0.75% | 0.75% | 0.75% | 0.75% | 0.75% | 0.75% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 9.25% | 9.25% | 9.25% | 9.25% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 11.25% | 11.25% | 11.25% | 11.25% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Regulatory Clause Revenues and Other Current Liabilities [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets, Deferred and Other Deferred Credits and Liabilities [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 42,000,000 | 42,000,000 | 42,000,000 | 42,000,000 | 42,000,000 | 42,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other regulatory liabilities current [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered fuel balance | $ 40,000,000 | $ 40,000,000 | $ 40,000,000 | $ 40,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Clause Revenues, under-recovered [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered fuel balance | 18,000,000 | 18,000,000 | 18,000,000 | 18,000,000 | 18,000,000 | 18,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Environmental Cost | 10,000,000 | 10,000,000 | 10,000,000 | 10,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Energy Conservation Costs | $ 4,000,000 | $ 3,000,000 | $ 4,000,000 | $ 3,000,000 | $ 4,000,000 | $ 4,000,000 | $ 3,000,000 | $ 3,000,000 | $ 4,000,000 | $ 4,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prime Rate [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.7947% | 3.7947% | 3.7947% | 3.7947% | 3.7947% | 3.7947% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 900,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | $ 62,500,000 | $ 62,500,000 | $ 62,500,000 | $ 62,500,000 | $ 62,500,000 | $ 62,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Current Estimate [Member] | Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost | 5,290,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum cap construction cost | 6,630,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pending Litigation [Member] | Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project Settlement Cost To Be Capitalized | 350,000,000 | 350,000,000 | 350,000,000 | 350,000,000 | 350,000,000 | 350,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project Settlement Cost To Be Capitalized, Amount Paid To Date | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | $ 120,000,000 | 120,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pending Litigation [Member] | Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project Settlement Cost To Be Capitalized, Amount Paid To Date | $ 121,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pending Litigation [Member] | Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Adjustment to Contract Price Related to Issues that May Impact Project Budget and Schedule | $ 714,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In-Service Asset Proposal [Member] | Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSC Retail Rate Increase (Decrease) | $ 126,000,000 | $ 159,000,000 | $ 159,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 49.733% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.225% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customer Refund | $ 11,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period to File Subsequent Rate Request | 18 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Bearing Refundable Deposit Related To Assets Sale [Member] | Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument, Interest Amount | $ 26,000,000 |
Joint Ownership Agreements (Det
Joint Ownership Agreements (Details) | 12 Months Ended | |||
Dec. 31, 2015USD ($)MW | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Aug. 31, 2014USD ($) | |
Joint Ownership Agreements (Textual) [Abstract] | ||||
Short-term Debt | $ 1,376,000,000 | $ 803,000,000 | ||
Alabama Power [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 14.00% | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 1,000 | |||
Jointly Owned Affiliate Equity | $ 118,000,000 | |||
Jointly Owned Affiliate Long Term Debt | 125,000,000 | |||
Jointly Owned Affiliate Long Term Debt Annual Interest Requirement | 3,000,000 | |||
Short-term Debt | $ 0 | 0 | ||
Dividends paid by equity method investment | 3,000,000 | $ 7,000,000 | ||
Ownership percentage, equity method investment | 50.00% | |||
Alabama Power [Member] | SEGCO [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 1,020 | |||
Share Of Purchased Power | $ 76,000,000 | 84,000,000 | 88,000,000 | |
Unconditional guarantee to pay outstanding pollution control revenue bond principal | 25,000,000 | |||
Alabama Power [Member] | SEGCO [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Short-term Debt | 52,000,000 | |||
Alabama Power [Member] | Senior notes due December 1, 2018 [Member] | SEGCO [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Guarantee of unsecured senior notes | $ 100,000,000 | |||
Alabama Power [Member] | Plant Miller (coal) Units 1 and 2 [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 91.84% | |||
Plant in Service | $ 1,518,000,000 | |||
Accumulated Depreciation | 587,000,000 | |||
Construction Work in Progress | $ 63,000,000 | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 1,320 | |||
Alabama Power [Member] | SEGCO [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 86.00% | |||
Alabama Power [Member] | Greene County [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 60.00% | |||
Plant in Service | $ 159,000,000 | |||
Accumulated Depreciation | 97,000,000 | |||
Construction Work in Progress | $ 20,000,000 | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 500 | |||
Georgia Power [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Short-term Debt | $ 158,000,000 | 156,000,000 | ||
Georgia Power [Member] | SEGCO [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Share Of Purchased Power | $ 78,000,000 | 84,000,000 | ||
Georgia Power [Member] | Purchased Power from Affiliates [Member] | SEGCO [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Share Of Purchased Power | $ 91,000,000 | |||
Georgia Power [Member] | Plant Vogtle Units 1 and 2 [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 45.70% | |||
Plant in Service | $ 3,503,000,000 | |||
Accumulated Depreciation | 2,084,000,000 | |||
Construction Work in Progress | $ 63,000,000 | |||
Georgia Power [Member] | Plant Hatch (nuclear) [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 50.10% | |||
Plant in Service | $ 1,230,000,000 | |||
Accumulated Depreciation | 568,000,000 | |||
Construction Work in Progress | $ 90,000,000 | |||
Georgia Power [Member] | Plant Scherer (coal) Units 1 and 2 [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 8.40% | |||
Plant in Service | $ 260,000,000 | |||
Accumulated Depreciation | 86,000,000 | |||
Construction Work in Progress | $ 1,000,000 | |||
Georgia Power [Member] | Plant Wansley (coal) [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 53.50% | |||
Plant in Service | $ 915,000,000 | |||
Accumulated Depreciation | 290,000,000 | |||
Construction Work in Progress | $ 13,000,000 | |||
Georgia Power [Member] | Rocky Mountain (pumped storage) [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 25.40% | |||
Plant in Service | $ 181,000,000 | |||
Accumulated Depreciation | 125,000,000 | |||
Construction Work in Progress | $ 0 | |||
Georgia Power [Member] | Intercession City (combustion turbine) [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 33.30% | |||
Plant in Service | $ 13,000,000 | |||
Accumulated Depreciation | 4,000,000 | |||
Construction Work in Progress | $ 0 | |||
Georgia Power [Member] | Vogtle Units 3 and 4 [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 45.70% | |||
Georgia Power [Member] | Plant Scherer Unit 3 (coal) [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 75.00% | |||
Plant in Service | $ 1,223,000,000 | |||
Accumulated Depreciation | 433,000,000 | |||
Construction Work in Progress | $ 1,000,000 | |||
Georgia Power [Member] | Alabama Power [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 1,020 | |||
Gulf Power [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Short-term Debt | $ 142,000,000 | 110,000,000 | ||
Gulf Power [Member] | Plant Scherer Unit 3 (coal) [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 25.00% | |||
Plant in Service | $ 395,000,000 | |||
Accumulated Depreciation | 136,000,000 | |||
Construction Work in Progress | $ 2,000,000 | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 818 | |||
Gulf Power [Member] | Plant Daniel Units 1 &2 2 [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 50.00% | |||
Plant in Service | $ 669,000,000 | |||
Accumulated Depreciation | 184,000,000 | |||
Construction Work in Progress | $ 9,000,000 | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 1,000 | |||
Mississippi Power [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Short-term Debt | $ 500,000,000 | 0 | ||
Mississippi Power [Member] | Greene County [Member] | ||||
Jointly owned utility plant interests | ||||
Construction Work in Progress | $ 6,000,000 | |||
Mississippi Power [Member] | Greene County [Member] | Alabama Power [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 40.00% | |||
Plant in Service | $ 152,000,000 | |||
Accumulated Depreciation | 56,000,000 | |||
Construction Work in Progress | $ 13,000,000 | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 500 | |||
Mississippi Power [Member] | Plant Daniel Units 1 &2 2 [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 50.00% | |||
Mississippi Power [Member] | Plant Daniel Units 1 &2 2 [Member] | Gulf Power [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 50.00% | |||
Plant in Service | $ 686,000,000 | |||
Accumulated Depreciation | 160,000,000 | |||
Construction Work in Progress | $ 10,000,000 | |||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 1,000 | |||
Southern Power [Member] | ||||
Joint Ownership Agreements (Textual) [Abstract] | ||||
Total Megawatt Capacity | MW | 659 | |||
Short-term Debt | $ 137,000,000 | $ 195,000,000 | ||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 65.00% | |||
Plant in Service | $ 157,000,000 | |||
Accumulated Depreciation | 53,000,000 | |||
Construction Work in Progress | $ 0 | |||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Orlando Utilities Commission [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 28.00% | |||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Florida Municipal Power Agency [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 3.50% | |||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Kissimmee Utility Authority [Member] | ||||
Jointly owned utility plant interests | ||||
Percent Ownership | 3.50% |
Income Taxes - Current and Defe
Income Taxes - Current and Deferred Income Tax Provisions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Federal - | |||
Current | $ (177) | $ 175 | $ 363 |
Deferred | 1,266 | 695 | 386 |
Total federal taxes | 1,089 | 870 | 749 |
State - | |||
Current | (33) | 93 | (10) |
Deferred | 138 | 14 | 110 |
Total state taxes | 105 | 107 | 100 |
Income taxes | 1,194 | 977 | 849 |
Deferred tax assets | 6,358 | 5,241 | |
Alabama Power [Member] | |||
Federal - | |||
Current | 110 | 198 | 243 |
Deferred | 320 | 225 | 160 |
Total federal taxes | 430 | 423 | 403 |
State - | |||
Current | 8 | 44 | 36 |
Deferred | 68 | 45 | 39 |
Total state taxes | 76 | 89 | 75 |
Income taxes | 506 | 512 | 478 |
Deferred tax assets | 1,511 | 1,141 | |
Georgia Power [Member] | |||
Federal - | |||
Current | 515 | 295 | 277 |
Deferred | 176 | 366 | 374 |
Total federal taxes | 691 | 661 | 651 |
State - | |||
Current | 81 | 82 | (30) |
Deferred | (3) | (14) | 102 |
Total state taxes | 78 | 68 | 72 |
Income taxes | 769 | 729 | 723 |
Deferred tax assets | 2,017 | 1,736 | |
Gulf Power [Member] | |||
Federal - | |||
Current | (3) | 23 | 5 |
Deferred | 80 | 52 | 63 |
Total federal taxes | 77 | 75 | 68 |
State - | |||
Current | 5 | 0 | (2) |
Deferred | 10 | 13 | 14 |
Total state taxes | 15 | 13 | 12 |
Income taxes | 92 | 88 | 80 |
Deferred tax assets | 216 | 171 | |
Mississippi Power [Member] | |||
Federal - | |||
Current | (768) | (431) | 23 |
Deferred | 704 | 183 | (343) |
Total federal taxes | (64) | (248) | (320) |
State - | |||
Current | (81) | 1 | 5 |
Deferred | 73 | (38) | (53) |
Total state taxes | (8) | (37) | (48) |
Income taxes | (72) | (285) | (368) |
Deferred tax assets | 1,400 | 1,251 | |
Southern Power [Member] | |||
Federal - | |||
Current | 12 | 179 | (120) |
Deferred | 10 | (166) | 159 |
Total federal taxes | 22 | 13 | 39 |
State - | |||
Current | (32) | (14) | (5) |
Deferred | 31 | (2) | 12 |
Total state taxes | (1) | (16) | 7 |
Income taxes | 21 | (3) | $ 46 |
Deferred tax assets | 794 | 481 | |
Unrealized Tax Credits [Member] | Southern Power [Member] | |||
State - | |||
Deferred tax assets | 551 | 305 | |
Unrealized Tax Credits [Member] | Deferred Charges Related To Income Taxes, Current [Member] | Other Noncurrent Assets [Member] | Southern Power [Member] | |||
State - | |||
Deferred tax assets | $ 246 | $ 305 |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | $ 18,678 | $ 16,256 |
Deferred tax assets - | ||
Total - deferred tax assets | 6,358 | 5,241 |
Valuation allowance | (2) | (49) |
Total deferred tax liabilities, net | 6,356 | 5,192 |
Accumulated deferred income taxes | 12,322 | 11,082 |
Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 12,767 | 11,125 |
Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,543 | 1,332 |
Leveraged lease basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 308 | 299 |
Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 579 | 613 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,720 | 1,675 |
Premium on reacquired debt [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 95 | 103 |
Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,378 | 1,390 |
Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,422 | 871 |
Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 586 | 523 |
Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 479 | 430 |
Over recovered fuel clause [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 104 | 0 |
Other property basis differences [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 695 | 453 |
Deferred costs [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 83 | 86 |
Investment Tax Credit Carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 742 | 480 |
Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 111 | 67 |
Other Comprehensive Income Losses [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 85 | 89 |
Asset retirement obligations-asset [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 1,422 | 871 |
Kemper IGCC Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 451 | 631 |
Deferred State Tax Assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 220 | 117 |
Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 246 | 342 |
Alabama Power [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 5,752 | 4,998 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,511 | 1,141 |
Accumulated deferred income taxes | 4,241 | 3,857 |
Accumulated deferred income taxes | 4,241 | 3,857 |
Alabama Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 3,917 | 3,429 |
Alabama Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 456 | 457 |
Alabama Power [Member] | Leveraged lease basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 28 | 30 |
Alabama Power [Member] | Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 200 | 215 |
Deferred tax assets - | ||
Total - deferred tax assets | 407 | 400 |
Alabama Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 375 | 366 |
Alabama Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 312 | 285 |
Alabama Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 175 | 157 |
Alabama Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 242 | 219 |
Alabama Power [Member] | Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 39 | 42 |
Alabama Power [Member] | Other Comprehensive Income Losses [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 20 | 19 |
Alabama Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 180 | 90 |
Alabama Power [Member] | Asset retirement obligation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 289 | 59 |
Deferred tax assets - | ||
Total - deferred tax assets | 600 | 344 |
Alabama Power [Member] | Storm Reserve [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 23 | 27 |
Georgia Power [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 7,644 | 7,210 |
Deferred tax assets - | ||
Total - deferred tax assets | 2,017 | 1,736 |
Accumulated deferred income taxes | 5,627 | 5,474 |
Accumulated deferred income taxes | 5,627 | 5,474 |
Georgia Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 4,909 | 4,732 |
Georgia Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 943 | 811 |
Georgia Power [Member] | Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 310 | 329 |
Deferred tax assets - | ||
Total - deferred tax assets | 642 | 642 |
Georgia Power [Member] | Premium on reacquired debt [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 61 | 66 |
Georgia Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 528 | 534 |
Georgia Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 706 | 497 |
Deferred tax assets - | ||
Total - deferred tax assets | 706 | 497 |
Georgia Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 187 | 160 |
Georgia Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 150 | 148 |
Georgia Power [Member] | Over recovered fuel clause [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 45 | 0 |
Georgia Power [Member] | Other property basis differences [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 88 | 86 |
Georgia Power [Member] | Deferred costs [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 83 | 86 |
Georgia Power [Member] | Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 47 | 46 |
Georgia Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 59 | 63 |
Georgia Power [Member] | Under recovered fuel clause [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 0 | 81 |
Georgia Power [Member] | Cost of removal [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 6 | 11 |
Georgia Power [Member] | Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 188 | 152 |
Georgia Power [Member] | Federal Tax Credit Carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 3 | 5 |
Gulf Power [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,109 | 968 |
Deferred tax assets - | ||
Total - deferred tax assets | 216 | 171 |
Accumulated deferred income taxes | 893 | 797 |
Accumulated deferred income taxes | 893 | 797 |
Gulf Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 812 | 777 |
Gulf Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 133 | 52 |
Gulf Power [Member] | Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 39 | 34 |
Gulf Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 59 | 60 |
Gulf Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 40 | 7 |
Gulf Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 26 | 22 |
Gulf Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 33 | 31 |
Gulf Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 19 | 18 |
Gulf Power [Member] | Pension and other employee benefits [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 65 | 66 |
Gulf Power [Member] | Fuel Recovery Clause [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 0 | 16 |
Gulf Power [Member] | Asset retirement obligation [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 40 | 7 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 26 | 18 |
Gulf Power [Member] | Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 18 | 18 |
Gulf Power [Member] | Property damage reserves-liability [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 15 | 13 |
Mississippi Power [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 2,162 | 1,397 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,400 | 1,251 |
Accumulated deferred income taxes | 762 | 146 |
Deferred state tax asset | 0 | 34 |
Accumulated deferred income taxes | 762 | 180 |
Mississippi Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,618 | 1,068 |
Mississippi Power [Member] | Property basis differences [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 451 | 263 |
Mississippi Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 66 | 68 |
Mississippi Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 71 | 19 |
Mississippi Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 163 | 52 |
Mississippi Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 0 | 1 |
Deferred tax assets - | ||
Total - deferred tax assets | 8 | 0 |
Mississippi Power [Member] | Over recovered fuel clause [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 51 | 0 |
Mississippi Power [Member] | Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 16 | 15 |
Mississippi Power [Member] | Kemper IGCC Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 451 | 631 |
Mississippi Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 13 | 15 |
Mississippi Power [Member] | Energy Cost Management Clause Over Recovered [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 0 | 1 |
Mississippi Power [Member] | NOL State Carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 152 | 57 |
Mississippi Power [Member] | Deferred Federal Tax Assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 48 | 0 |
Mississippi Power [Member] | Energy Cost Management Clause Under Recovered [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 13 | 0 |
Mississippi Power [Member] | Pension and other employee benefits [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 30 | 35 |
Deferred tax assets - | ||
Total - deferred tax assets | 92 | 92 |
Mississippi Power [Member] | Kemper IGCC regulatory assets [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 86 | 62 |
Mississippi Power [Member] | Under recovered fuel clause [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 0 | 3 |
Mississippi Power [Member] | Asset retirement obligation [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 71 | 19 |
Mississippi Power [Member] | Rate Differential [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 115 | 89 |
Mississippi Power [Member] | Property insurance [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 25 | 24 |
Mississippi Power [Member] | Premium on long-term debt [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 18 | 21 |
Mississippi Power [Member] | Interest rate hedges [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 4 | 5 |
Mississippi Power [Member] | Kemper Rate Factor - Regulatory Liability Retail [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 0 | 108 |
Southern Power [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,393 | 1,032 |
Deferred tax assets - | ||
Total - deferred tax assets | 794 | 481 |
Valuation allowance | (2) | (8) |
Total deferred tax liabilities, net | 792 | 473 |
Accumulated deferred income taxes | 601 | 559 |
Accumulated deferred income taxes | 601 | 559 |
Southern Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 4 | 6 |
Southern Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 40 | 29 |
Southern Power [Member] | Other property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 3 | 3 |
Southern Power [Member] | Investment Tax Credit Carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 149 | 102 |
Southern Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 18 | 4 |
Southern Power [Member] | Accelerated depreciation and other property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,364 | 1,006 |
Southern Power [Member] | Levelized capacity revenues [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 22 | 17 |
Deferred tax assets - | ||
Total - deferred tax assets | 4 | 5 |
Southern Power [Member] | State Net Operating Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 13 | 15 |
Southern Power [Member] | Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 15 | 15 |
Southern Power [Member] | Unrealized Tax Credits [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 551 | 305 |
Southern Power [Member] | Unrealized Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | $ 4 | 6 |
Scenario, Previously Reported [Member] | ||
Deferred tax assets - | ||
Accumulated deferred income taxes | $ 11,064 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Federal Statutory Income Tax Rate (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | 1.90% | 2.30% | 2.50% |
Employee stock plans dividend deduction | (1.20%) | (1.40%) | (1.60%) |
Non-deductible book depreciation | 1.20% | 1.40% | 1.50% |
AFUDC-Equity | (2.20%) | (2.90%) | (2.60%) |
ITC basis difference | (1.50%) | (1.60%) | (1.20%) |
Other | (0.30%) | (0.30%) | (0.50%) |
Effective income tax rate | 32.90% | 32.50% | 33.10% |
Alabama Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 3.80% | 4.40% | 4.00% |
Non-deductible book depreciation | 1.20% | 1.10% | 1.00% |
Difference in prior years' deferred and current tax rate | (0.10%) | (0.10%) | (0.10%) |
AFUDC-Equity | (1.60%) | (1.30%) | (0.90%) |
Other | 0.10% | (0.10%) | (0.10%) |
Effective income tax rate | 38.40% | 39.00% | 38.90% |
Georgia Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 2.50% | 2.20% | 2.50% |
Non-deductible book depreciation | 1.20% | 1.30% | 1.30% |
AFUDC-Equity | (0.70%) | (0.80%) | (0.60%) |
Other | (0.40%) | (0.70%) | (0.40%) |
Effective income tax rate | 37.60% | 37.00% | 37.80% |
Gulf Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 3.90% | 3.50% | 3.50% |
Non-deductible book depreciation | 0.50% | 0.40% | 0.50% |
Difference in prior years' deferred and current tax rate | (0.10%) | (0.10%) | (0.20%) |
AFUDC-Equity | (1.80%) | (1.80%) | (1.10%) |
Other | (0.60%) | 0.10% | (0.10%) |
Effective income tax rate | 36.90% | 37.10% | 37.60% |
Mississippi Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | (35.00%) | (35.00%) | (35.00%) |
State income tax, net of federal deduction | (6.30%) | (4.00%) | (3.70%) |
Non-deductible book depreciation | 1.30% | 0.10% | 0.10% |
AFUDC-Equity | (49.60%) | (7.80%) | (5.00%) |
Other | (2.90%) | 0.10% | (0.10%) |
Effective income tax rate | (92.50%) | (46.60%) | (43.70%) |
Southern Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | (0.30%) | (6.00%) | 2.20% |
Amortization of ITC | (5.00%) | (4.30%) | (1.70%) |
ITC basis difference | (21.50%) | (27.70%) | (14.50%) |
Other | 0.20% | 1.10% | 0.30% |
Effective income tax rate | 8.40% | (1.90%) | 21.30% |
Income Taxes - Changes in Unrec
Income Taxes - Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | $ 170 | $ 7 | $ 70 |
Tax positions from current periods | 43 | 64 | 3 |
Tax positions increase from prior periods | 240 | 102 | 0 |
Tax positions decrease from prior periods | (20) | (3) | (66) |
Unrecognized tax benefits at end of year | 433 | 170 | 7 |
Georgia Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 0 | 0 | 23 |
Tax positions increase from prior periods | 3 | 0 | 0 |
Tax positions decrease from prior periods | 0 | 0 | (23) |
Unrecognized tax benefits at end of year | 3 | 0 | 0 |
Mississippi Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 165 | 4 | 6 |
Tax positions from current periods | 32 | 58 | 0 |
Tax positions increase from prior periods | 224 | 103 | |
Tax positions decrease from prior periods | (2) | ||
Unrecognized tax benefits at end of year | 421 | 165 | 4 |
Southern Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 5 | 2 | 3 |
Tax positions from current periods | 9 | 5 | 2 |
Tax positions decrease from prior periods | (6) | (2) | (3) |
Unrecognized tax benefits at end of year | $ 8 | $ 5 | $ 2 |
Income Taxes - Impact of Unreco
Income Taxes - Impact of Unrecognized Tax Benefits on Effective Tax Rate, If Recognized (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Impact on effective tax rate | ||||
Tax positions impacting the effective tax rate | $ 10 | $ 10 | $ 7 | |
Tax positions not impacting the effective tax rate | 423 | 160 | 0 | |
Balance of unrecognized tax benefits | 433 | 170 | 7 | $ 70 |
Mississippi Power [Member] | ||||
Impact on effective tax rate | ||||
Tax positions impacting the effective tax rate | (2) | 4 | 4 | |
Tax positions not impacting the effective tax rate | 423 | 161 | 0 | |
Balance of unrecognized tax benefits | $ 421 | $ 165 | $ 4 | $ 6 |
Income Taxes - Accrued Interest
Income Taxes - Accrued Interest for Unrecognized Tax Benefits (Details) - Mississippi Power [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward] | |||
Interest accrued at beginning of year | $ 3 | $ 1 | $ 1 |
Interest accrued during the period | 6 | 2 | 0 |
Balance at end of year | $ 9 | $ 3 | $ 1 |
Income Taxes - Textual (Details
Income Taxes - Textual (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 30, 2015 | Dec. 31, 2012 | |
Income Tax Disclosure [Line Items] | |||||
Net cash payments/(refunds) for income taxes | $ (9) | $ 272 | $ 139 | ||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | $ 3.5 | $ 24 | |||
Period Of Operating Loss Carryforward | 4 years | ||||
Deferred tax assets | $ 6,358 | 5,241 | |||
Tax Credit Carryforward, Amount | 554 | ||||
State Investment Tax Credit | 188 | ||||
Tax regulatory assets | 1,600 | ||||
Tax regulatory liabilities | 187 | ||||
Amortization of deferred investment tax credits | 21 | 22 | 16 | ||
Unrecognized Tax Benefits | $ 433 | 170 | 7 | $ 70 | |
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | ||||
Investment Tax Credit Carryforward [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Deferred tax assets | $ 742 | 480 | |||
Alabama Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net cash payments/(refunds) for income taxes | 121 | 436 | 296 | ||
Deferred tax assets | 1,511 | 1,141 | |||
Tax regulatory assets | 523 | ||||
Tax regulatory liabilities | 70 | ||||
Amortization of deferred investment tax credits | 8 | 8 | 8 | ||
Georgia Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net cash payments/(refunds) for income taxes | 506 | 507 | 298 | ||
Deferred tax assets | 2,017 | 1,736 | |||
State Investment Tax Credit | 33 | 34 | 27 | ||
Tax regulatory assets | 683 | ||||
Tax regulatory liabilities | 105 | ||||
Amortization of deferred investment tax credits | 10 | 10 | 5 | ||
Federal Tax Credits | 3 | ||||
State Investment Tax Credit Carryforward | 188 | ||||
Unrecognized Tax Benefits | 3 | 0 | 0 | 23 | |
Gulf Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net cash payments/(refunds) for income taxes | (7) | 44 | (11) | ||
Deferred tax assets | 216 | 171 | |||
Tax regulatory assets | 61 | ||||
Tax regulatory liabilities | 3 | ||||
Amortization of deferred investment tax credits | $ 1 | 0 | 1.4 | ||
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | ||||
Mississippi Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net cash payments/(refunds) for income taxes | $ (33) | (379) | (134) | ||
Net operating loss carryforward | 3,000 | ||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 97 | ||||
Deferred tax assets | 1,400 | 1,251 | |||
Tax regulatory assets | 291 | ||||
Tax regulatory liabilities | 8 | ||||
Amortization of deferred investment tax credits | 1 | ||||
Unrecognized Tax Benefits | 421 | 165 | 4 | 6 | |
Unrecognized Tax Benefits, Interest on Income Taxes Expense | 6 | 2 | 0 | ||
Mississippi Power [Member] | Kemper IGCC [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Unrecognized Tax Benefits | 423 | ||||
Unrecognized Tax Benefits, Interest on Income Taxes Expense | 9 | ||||
Southern Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net cash payments/(refunds) for income taxes | (518) | (220) | (226) | ||
Net operating loss carryforward | 225 | 247 | |||
Deferred tax assets | 794 | 481 | |||
Increase (decrease) in deferred tax assets valuation allowance | 87 | ||||
Operating Loss Carryforwards In Year Three | 40 | ||||
Operating Loss Carryforwards In Year Four | 185 | ||||
Amortization of deferred investment tax credits | $ 19 | 11 | 6 | ||
Reduction in Tax Basis of Assets Under Option One | 50.00% | ||||
Unrecognized Tax Benefits | $ 8 | 5 | 2 | $ 3 | |
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | ||||
Southern Power [Member] | Operating Loss Carryforward [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Deferred tax assets | $ 8 | 9 | |||
Southern Power [Member] | Investment Tax Credit Carryforward [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Deferred tax assets | 149 | 102 | |||
Southern Power [Member] | Investment Tax Credit Carryforward [Member] | Nacogdoches Biomass Generating Plant [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Tax credit carryforward | 162 | 74 | 158 | ||
Reduction in income tax expense, investment tax credits | 54 | 48 | 31 | ||
Deferred Tax Liability, Noncurrent [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 488 | $ 143 | |||
Prepaid Expense, Current [Member] | Mississippi Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 121 | ||||
Prepaid Expense, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | Alabama Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 20 | ||||
Prepaid Expense, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | Gulf Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 3 | ||||
Prepaid Expense, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | Mississippi Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 105 | ||||
Prepaid Expense, Current [Member] | Other Noncurrent Assets [Member] | Mississippi Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 16 | ||||
Prepaid Expense, Current [Member] | Other Noncurrent Assets [Member] | Southern Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 306 | ||||
Deferred Charges Related To Income Taxes, Current [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 506 | ||||
Deferred Charges Related To Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 488 | ||||
Deferred Charges Related To Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | Georgia Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 34 | ||||
Deferred Charges Related To Income Taxes, Current [Member] | Other Noncurrent Assets [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 18 | ||||
Accrued Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 2 | ||||
Accrued Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | Alabama Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | 2 | ||||
Accrued Income Taxes, Current [Member] | Deferred Tax Liability, Noncurrent [Member] | Southern Power [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Prior Period Reclassification Adjustment | $ 2 | ||||
Georgia [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net operating loss carryforward | 697 | ||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 27 | ||||
Mississippi [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net operating loss carryforward | 3,000 | ||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 97 | ||||
New Mexico [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net operating loss carryforward | 133 | ||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 5 | ||||
Florida [Member] | |||||
Income Tax Disclosure [Line Items] | |||||
Net operating loss carryforward | 115 | ||||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | $ 4 |
Financing - Scheduled Maturitie
Financing - Scheduled Maturities and Redemptions of Securities Due Within One Year (Details) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |||
May. 31, 2015$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Feb. 26, 2016USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($)shares | |
Scheduled maturities and redemptions of securities due within one year | |||||
Senior notes | $ | $ 1,810 | $ 2,375 | |||
Other long-term debt | $ | 829 | 775 | |||
Capitalized leases | $ | 32 | 31 | |||
Total | $ | (1) | (4) | |||
Pollution control revenue bonds | $ | 4 | 152 | |||
Total | $ | 2,674 | 3,329 | |||
Georgia Power [Member] | |||||
Scheduled maturities and redemptions of securities due within one year | |||||
Senior notes | $ | 700 | 1,050 | |||
Capitalized leases | $ | 8 | 6 | |||
Total | $ | 0 | (4) | |||
Pollution control revenue bonds | $ | 4 | 98 | |||
Total | $ | 712 | 1,150 | |||
Alabama Power [Member] | |||||
Scheduled maturities and redemptions of securities due within one year | |||||
Total | $ | $ 200 | $ 454 | |||
Alabama Power [Member] | 4.92% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0492 | ||||
Par Value/Stated Capital Per Share | $ 100 | ||||
Temporary Equity, Shares Outstanding | shares | 80,000 | ||||
Redemption Price Per Share | $ 103.23 | ||||
Alabama Power [Member] | 4.72% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0472 | ||||
Par Value/Stated Capital Per Share | $ 100 | ||||
Temporary Equity, Shares Outstanding | shares | 50,000 | ||||
Redemption Price Per Share | $ 102.18 | ||||
Alabama Power [Member] | 4.64% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0464 | ||||
Par Value/Stated Capital Per Share | $ 100 | ||||
Temporary Equity, Shares Outstanding | shares | 60,000 | ||||
Redemption Price Per Share | $ 103.14 | ||||
Alabama Power [Member] | 4.60% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0460 | ||||
Par Value/Stated Capital Per Share | $ 100 | ||||
Temporary Equity, Shares Outstanding | shares | 100,000 | ||||
Redemption Price Per Share | $ 104.20 | ||||
Alabama Power [Member] | 4.52% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0452 | ||||
Par Value/Stated Capital Per Share | $ 100 | ||||
Temporary Equity, Shares Outstanding | shares | 50,000 | ||||
Redemption Price Per Share | $ 102.93 | ||||
Alabama Power [Member] | 4.20% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0420 | ||||
Par Value/Stated Capital Per Share | $ 100 | ||||
Temporary Equity, Shares Outstanding | shares | 135,115 | ||||
Redemption Price Per Share | $ 105 | ||||
Alabama Power [Member] | 5.83% Class A Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0583 | ||||
Par Value/Stated Capital Per Share | $ 25 | ||||
Temporary Equity, Shares Outstanding | shares | 1,520,000 | ||||
Alabama Power [Member] | 6.450% Preference Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.06450 | ||||
Par Value/Stated Capital Per Share | $ 25 | ||||
Temporary Equity, Shares Outstanding | shares | 6,000,000 | ||||
Alabama Power [Member] | 6.500% Preference Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.06500 | ||||
Par Value/Stated Capital Per Share | $ 25 | ||||
Temporary Equity, Shares Outstanding | shares | 2,000,000 | ||||
Alabama Power [Member] | 5.20% Class A Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.052 | 0.0520 | |||
Par Value/Stated Capital Per Share | $ 25 | ||||
Temporary Equity, Shares Outstanding | shares | 6,480,000 | ||||
Alabama Power [Member] | 5.30% Class A Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.053 | 0.0530 | |||
Par Value/Stated Capital Per Share | $ 25 | ||||
Temporary Equity, Shares Outstanding | shares | 4,000,000 | ||||
Alabama Power [Member] | 5.625% Preference Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.05625 | 0.05625 | |||
Temporary Equity, Shares Outstanding | shares | 6,000,000 | ||||
Mississippi Power [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Temporary Equity, Shares Outstanding | shares | 334,210 | 334,210 | |||
Scheduled maturities and redemptions of securities due within one year | |||||
Senior notes | $ | $ 300 | $ 0 | |||
Capitalized leases | $ | 3 | 3 | |||
Bank term loans | $ | 425 | 775 | |||
Total | $ | $ 728 | $ 778 | |||
Mississippi Power [Member] | 4.40% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par Value/Stated Capital Per Share | $ 100,000,000 | ||||
Temporary Equity, Shares Outstanding | shares | 8,867,000,000 | ||||
Redemption Price Per Share | $ 104.32 | ||||
Mississippi Power [Member] | 4.72% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par Value/Stated Capital Per Share | $ 100,000,000 | ||||
Temporary Equity, Shares Outstanding | shares | 16,700,000,000 | ||||
Redemption Price Per Share | $ 102.25 | ||||
Mississippi Power [Member] | 4.60% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par Value/Stated Capital Per Share | $ 100,000,000 | ||||
Temporary Equity, Shares Outstanding | shares | 8,643,000,000 | ||||
Redemption Price Per Share | $ 107 | ||||
Mississippi Power [Member] | 5.25% Redeemable Preferred Stock [Member] | |||||
Redeemable Preferred/Preference Stock [Abstract] | |||||
Par Value/Stated Capital Per Share | $ 25,000,000 | ||||
Temporary Equity, Shares Outstanding | shares | 1,200,000,000,000 | ||||
Redemption Price Per Share | $ 25 | ||||
Unsecured Debt [Member] | Alabama Power [Member] | |||||
Debt Disclosure [Line Items] | |||||
Redemption Amount of Principal Notes | $ | $ 250 | ||||
Subsequent Event [Member] | Series FF [Member] | Unsecured Debt [Member] | Alabama Power [Member] | |||||
Debt Disclosure [Line Items] | |||||
Redemption Amount of Principal Notes | $ | $ 200 |
Financing - Committed Credit Ar
Financing - Committed Credit Arrangements With Banks (Details) - USD ($) | Dec. 31, 2015 | Aug. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2012 |
Credit arrangements by company | ||||
Expires, 2015 | $ 410,000,000 | |||
Expires, 2016 | 30,000,000 | |||
Expires, 2017 | 1,665,000,000 | |||
Expires, 2020 | 4,400,000,000 | |||
Total | 6,505,000,000 | |||
Unused | 6,428,000,000 | |||
Executable Term-Loans, One Year | 80,000,000 | |||
Executable Term-Loans, Two Years | 15,000,000 | |||
Due Within One Year, Term Out | 95,000,000 | |||
Due Within One Year, No Term Out | 315,000,000 | |||
Southern Company [Member] | ||||
Credit arrangements by company | ||||
Expires, 2015 | 0 | |||
Expires, 2016 | 0 | |||
Expires, 2017 | 1,000,000,000 | |||
Expires, 2020 | 1,250,000,000 | |||
Total | 2,250,000,000 | $ 1,250,000,000 | $ 1,000,000,000 | |
Unused | 2,250,000,000 | |||
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 [Member] | ||||
Credit arrangements by company | ||||
Expires, 2015 | 40,000,000 | |||
Expires, 2016 | 0 | |||
Expires, 2017 | 500,000,000 | |||
Expires, 2020 | 800,000,000 | |||
Total | 1,340,000,000 | |||
Unused | 1,340,000,000 | |||
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 | 40,000,000 | |||
Georgia Power [Member] | ||||
Credit arrangements by company | ||||
Expires, 2015 | 0 | |||
Expires, 2016 | 0 | |||
Expires, 2017 | 0 | |||
Expires, 2020 | 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 [Member] | ||||
Credit arrangements by company | ||||
Expires, 2015 | 80,000,000 | |||
Expires, 2016 | 30,000,000 | |||
Expires, 2017 | 165,000,000 | |||
Expires, 2020 | 0 | |||
Total | 275,000,000 | |||
Unused | 275,000,000 | |||
Executable Term-Loans, One Year | 50,000,000 | |||
Executable Term-Loans, Two Years | 0 | |||
Due Within One Year, Term Out | 50,000,000 | |||
Due Within One Year, No Term Out | 30,000,000 | |||
Mississippi Power [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Deposit Liability, Current | $ 150,000,000 | |||
Credit arrangements by company | ||||
Expires, 2015 | 220,000,000 | |||
Expires, 2016 | 0 | |||
Expires, 2017 | 0 | |||
Expires, 2020 | 0 | |||
Total | 220,000,000 | |||
Unused | 195,000,000 | |||
Executable Term-Loans, One Year | 30,000,000 | |||
Executable Term-Loans, Two Years | 15,000,000 | |||
Due Within One Year, Term Out | 45,000,000 | |||
Due Within One Year, No Term Out | 175,000,000 | |||
Southern Power [Member] | ||||
Credit arrangements by company | ||||
Expires, 2015 | 0 | |||
Expires, 2016 | 0 | |||
Expires, 2017 | 0 | |||
Expires, 2020 | 600,000,000 | |||
Total | 600,000,000 | $ 600,000,000 | 500,000,000 | |
Unused | 566,000,000 | $ 488,000,000 | ||
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 | |||
Other Subsidiaries [Member] | ||||
Credit arrangements by company | ||||
Expires, 2015 | 70,000,000 | |||
Expires, 2016 | 0 | |||
Expires, 2017 | 0 | |||
Expires, 2020 | 0 | |||
Total | 70,000,000 | |||
Unused | 70,000,000 | |||
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 | 70,000,000 | |||
Scenario, Plan [Member] | Bridge Agreement [Member] | ||||
Credit arrangements by company | ||||
Total | $ 8,100,000,000 |
Financing - Short-term Borrowin
Financing - Short-term Borrowings (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Short-term Debt [Line Items] | ||
Expires, 2017 | $ 1,665 | |
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | $ 1,240 | $ 803 |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.90% | 0.30% |
Commercial paper [Member] | ||
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | $ 740 | $ 803 |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.70% | 0.30% |
Short-term bank debt [Member] | ||
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | $ 500 | $ 0 |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 1.40% | 0.00% |
Parent Company [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | $ 1,000 | |
Georgia Power [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | 0 | |
Georgia Power [Member] | Commercial paper [Member] | ||
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | $ 158 | $ 156 |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.60% | 0.30% |
Alabama Power [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | $ 500 | |
Gulf Power [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | 165 | |
Gulf Power [Member] | Commercial paper [Member] | ||
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | $ 142 | $ 110 |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.70% | 0.30% |
Mississippi Power [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | $ 0 | |
Mississippi Power [Member] | Commercial paper [Member] | ||
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | 0 | $ 0 |
Southern Power [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | 0 | |
Southern Power [Member] | Commercial paper [Member] | ||
Short-term borrowings | ||
Short-term Debt at the End of the Period, Amount Outstanding | 0 | $ 195 |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.40% | |
Other Subsidiaries [Member] | ||
Short-term Debt [Line Items] | ||
Expires, 2017 | $ 0 |
Financing - Schedule Of Credit
Financing - Schedule Of Credit Arrangements With Project Credit Facilities (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Aug. 31, 2015 | Dec. 31, 2014 |
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 6,505 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 6,428 | ||
Southern Power [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 600 | $ 600 | $ 500 |
Line of Credit Facility, Remaining Borrowing Capacity | 566 | $ 488 | |
Southern Power [Member] | Construction Loan Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 235 | ||
Southern Power [Member] | Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 660 | ||
Southern Power [Member] | Construction Loan And Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 895 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 758 | ||
Southern Power [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 149 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 81 | ||
Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | Construction Loan Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 86 | ||
Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 172 | ||
Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | Construction Loan And Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 258 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 147 | ||
Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 77 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 26 | ||
Southern Power [Member] | RE Roserock Holdings, LLC [Member] | Construction Loan Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 63 | ||
Southern Power [Member] | RE Roserock Holdings, LLC [Member] | Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 180 | ||
Southern Power [Member] | RE Roserock Holdings, LLC [Member] | Construction Loan And Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 243 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 243 | ||
Southern Power [Member] | RE Roserock Holdings, LLC [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 23 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 23 | ||
Southern Power [Member] | RE Garland Holdings, LLC [Member] | Construction Loan Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 86 | ||
Southern Power [Member] | RE Garland Holdings, LLC [Member] | Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 308 | ||
Southern Power [Member] | RE Garland Holdings, LLC [Member] | Construction Loan And Bridge Loan [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 394 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 368 | ||
Southern Power [Member] | RE Garland Holdings, LLC [Member] | Letter of Credit [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 49 | ||
Line of Credit Facility, Remaining Borrowing Capacity | $ 32 |
Financing - Textual (Details)
Financing - Textual (Details) | Jul. 15, 2015USD ($) | Feb. 20, 2014USD ($) | Dec. 31, 2015USD ($)leased_asset_unitsseriesshares | Nov. 30, 2015USD ($) | Sep. 30, 2015USD ($) | Aug. 31, 2015USD ($) | Jul. 31, 2015USD ($) | Jun. 30, 2015USD ($) | May. 31, 2015USD ($)$ / sharesshares | Apr. 30, 2015USD ($)loan | Mar. 31, 2015USD ($) | Jan. 31, 2014USD ($)shares | Sep. 30, 2013 | Dec. 31, 2015USD ($)leased_asset_unitsseriesshares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | Feb. 26, 2016USD ($) | Oct. 31, 2015USD ($) | Dec. 11, 2014USD ($) | Oct. 31, 2014USD ($) | Mar. 31, 2012USD ($) |
Debt Instrument [Line Items] | ||||||||||||||||||||||
Redeemable preferred stock | $ 118,000,000 | $ 118,000,000 | $ 375,000,000 | $ 375,000,000 | ||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 2,674,000,000 | 2,674,000,000 | 3,329,000,000 | |||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Proceeds from issuance of junior subordinated notes | 206,000,000 | 206,000,000 | 206,000,000 | |||||||||||||||||||
Other Long-term Debt | 6,808,000,000 | 6,808,000,000 | 4,719,000,000 | |||||||||||||||||||
Senior notes, current | 1,810,000,000 | 1,810,000,000 | 2,375,000,000 | |||||||||||||||||||
Other Long-term Debt | 829,000,000 | 829,000,000 | 775,000,000 | |||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2014 | 2,700,000,000 | 2,700,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 2,400,000,000 | 2,400,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 1,700,000,000 | 1,700,000,000 | ||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four | 1,200,000,000 | 1,200,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 1,400,000,000 | 1,400,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2015 | 1,360,000,000 | 1,360,000,000 | 1,360,000,000 | |||||||||||||||||||
Long-term debt maturities, 2016 | 1,995,000,000 | 1,995,000,000 | 1,495,000,000 | |||||||||||||||||||
Long-term debt maturities, 2018 | 1,176,000,000 | 1,176,000,000 | 1,175,000,000 | |||||||||||||||||||
Long-term debt maturities, 2019 | 1,327,000,000 | 1,327,000,000 | 425,000,000 | |||||||||||||||||||
Long-term debt maturities, 2017 | $ 1,697,000,000 | $ 1,697,000,000 | 850,000,000 | |||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 70.00% | 65.00% | 70.00% | |||||||||||||||||||
Senior Notes outstanding | $ 19,100,000,000 | $ 19,100,000,000 | 18,200,000,000 | |||||||||||||||||||
Capitalized lease obligations | 146,000,000 | 146,000,000 | 159,000,000 | |||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 24,253,000,000 | 24,253,000,000 | 24,059,000,000 | |||||||||||||||||||
Unused credit with banks | 6,428,000,000 | 6,428,000,000 | ||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 1,800,000,000 | 1,800,000,000 | ||||||||||||||||||||
Short Term Borrowings Excluding Other Energy Service Contracts | 1,240,000,000 | 1,240,000,000 | 803,000,000 | |||||||||||||||||||
Remarketed pollution control bonds | 181,000,000 | |||||||||||||||||||||
Long-term Pollution Control Bond, Current | 4,000,000 | 4,000,000 | $ 152,000,000 | |||||||||||||||||||
Expires, 2020 | $ 4,400,000,000 | $ 4,400,000,000 | ||||||||||||||||||||
Common Stock, Shares, Issued | shares | 915,000,000 | 915,000,000 | 909,000,000 | |||||||||||||||||||
Proceeds from Issuance of Common Stock | $ 256,000,000 | $ 806,000,000 | 695,000,000 | |||||||||||||||||||
Short-term Debt | $ 1,376,000,000 | $ 1,376,000,000 | 803,000,000 | |||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 6,505,000,000 | $ 6,505,000,000 | ||||||||||||||||||||
Building [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capital Leased Assets, Gross | 61,000,000 | 61,000,000 | 61,000,000 | |||||||||||||||||||
Trust Preferred Securities Subject to Mandatory Redemption [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Preferred securities, outstanding | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||
Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 600,000,000 | 600,000,000 | ||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 110,000,000 | 110,000,000 | 0 | |||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Other Long-term Debt | 309,000,000 | 309,000,000 | 309,000,000 | |||||||||||||||||||
Long-term debt maturities, 2015 | 110,000,000 | 110,000,000 | 110,000,000 | |||||||||||||||||||
Long-term debt maturities, 2016 | 85,000,000 | 85,000,000 | 85,000,000 | |||||||||||||||||||
Long-term debt maturities, 2019 | $ 175,000,000 | $ 175,000,000 | 175,000,000 | |||||||||||||||||||
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 outstanding | 1,010,000,000 | 1,010,000,000 | 1,070,000,000 | |||||||||||||||||||
Secured Debt | 41,000,000 | 41,000,000 | 41,000,000 | |||||||||||||||||||
Pollution control revenue bonds, outstanding | 309,000,000 | 309,000,000 | 309,000,000 | |||||||||||||||||||
Repayments of Senior Debt | 60,000,000 | 75,000,000 | 90,000,000 | |||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,296,000,000 | 1,296,000,000 | 1,296,000,000 | |||||||||||||||||||
Unused credit with banks | 275,000,000 | 275,000,000 | ||||||||||||||||||||
Pollution Control Revenue Bonds Required To Be Remarketed | $ 33,000,000 | $ 33,000,000 | ||||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | 100.00% | ||||||||||||||||||||
Expires, 2020 | $ 0 | $ 0 | ||||||||||||||||||||
Common Stock, Shares, Issued | shares | 200,000 | |||||||||||||||||||||
Proceeds from Issuance of Common Stock | $ 20,000,000 | $ 20,000,000 | 50,000,000 | 40,000,000 | ||||||||||||||||||
Number of Issuance Pollution Control Revenue Bonds | series | 2 | 2 | ||||||||||||||||||||
Short-term Debt | $ 142,000,000 | $ 142,000,000 | 110,000,000 | |||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 275,000,000 | $ 275,000,000 | ||||||||||||||||||||
Gulf Power [Member] | Minimum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redeemable preferred stock, redemption period | 5 years | |||||||||||||||||||||
Gulf Power [Member] | Maximum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redeemable preferred stock, redemption period | 10 years | |||||||||||||||||||||
Gulf Power [Member] | Secured Debt [Member] | Plant Daniel [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 41,000,000 | $ 41,000,000 | ||||||||||||||||||||
Gulf Power [Member] | First Series Two Thousand Fourteen [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Revenue Bond Issuances and Reofferings of Purchased Bonds | $ 13,000,000 | |||||||||||||||||||||
Gulf Power [Member] | Series Two Thousand Fourteen A [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 60,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.65% | |||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Line of Credit Facility, Increase (Decrease), Net | $ 150,000,000 | |||||||||||||||||||||
Line Of Credit Expire Year Three Terminated | 150,000,000 | |||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 712,000,000 | 712,000,000 | 1,150,000,000 | |||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,000,000,000 | 400,000,000 | $ 600,000,000 | 400,000,000 | $ 200,000,000 | |||||||||||||||||
Other Long-term Debt | 4,024,000,000 | 4,024,000,000 | 2,883,000,000 | |||||||||||||||||||
Senior notes, current | 700,000,000 | 700,000,000 | 1,050,000,000 | |||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2014 | 712,000,000 | 712,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 459,000,000 | 459,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 761,000,000 | 761,000,000 | ||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four | 512,000,000 | 512,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 49,000,000 | 49,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2015 | 0 | 0 | 1,050,000,000 | |||||||||||||||||||
Long-term debt maturities, 2016 | 250,000,000 | 250,000,000 | 250,000,000 | |||||||||||||||||||
Long-term debt maturities, 2018 | 747,000,000 | 747,000,000 | 250,000,000 | |||||||||||||||||||
Long-term debt maturities, 2019 | 502,000,000 | 502,000,000 | 500,000,000 | |||||||||||||||||||
Long-term debt maturities, 2017 | $ 450,000,000 | $ 450,000,000 | 450,000,000 | |||||||||||||||||||
Bank Loans Period Of Extension | 3 months | |||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | $ 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% | |||||||||||||||||||||
Payments of Debt Issuance Costs | $ 66,000,000 | |||||||||||||||||||||
Senior Notes outstanding | $ 6,300,000,000 | $ 6,300,000,000 | 6,900,000,000 | |||||||||||||||||||
Amortization Period For Line Of Credit Facility | 5 years | |||||||||||||||||||||
Pollution control revenue bonds, outstanding | 1,800,000,000 | 1,800,000,000 | 1,600,000,000 | |||||||||||||||||||
Repayments of Senior Debt | 1,175,000,000 | 0 | 1,775,000,000 | |||||||||||||||||||
Capitalized lease obligations | 183,000,000 | 183,000,000 | 40,000,000 | |||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 10,903,000,000 | 10,903,000,000 | 11,222,000,000 | |||||||||||||||||||
Unused credit with banks | 1,732,000,000 | 1,732,000,000 | ||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 872,000,000 | 872,000,000 | ||||||||||||||||||||
Pollution Control Revenue Bonds Required To Be Remarketed | 69,000,000 | 69,000,000 | ||||||||||||||||||||
Long-term Pollution Control Bond, Current | $ 4,000,000 | $ 4,000,000 | 98,000,000 | |||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | 100.00% | ||||||||||||||||||||
Expires, 2020 | $ 1,750,000,000 | $ 1,750,000,000 | ||||||||||||||||||||
Short-term Debt | 158,000,000 | $ 158,000,000 | 156,000,000 | |||||||||||||||||||
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 | ||||||||||||||||||||
Georgia Power [Member] | Corporate, Non-Segment [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capital Leased Assets, Gross | 61,000,000 | 61,000,000 | ||||||||||||||||||||
Capitalized lease obligations | 61,000,000 | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 26,000,000 | 26,000,000 | 21,000,000 | |||||||||||||||||||
Georgia Power [Member] | Building [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | $ 35,000,000 | $ 35,000,000 | $ 40,000,000 | |||||||||||||||||||
Georgia Power [Member] | Debt Held Since 2013 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Remarketing Revenue Bond | $ 104,600,000 | |||||||||||||||||||||
Revenue Bond Issuances and Reofferings of Purchased Bonds | 10,000,000 | |||||||||||||||||||||
Georgia Power [Member] | Debt Held Since 2009 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Remarketing Revenue Bond | $ 89,200,000 | |||||||||||||||||||||
Revenue Bond Issuances and Reofferings of Purchased Bonds | 94,600,000 | |||||||||||||||||||||
Georgia Power [Member] | Debt Held Since 2010 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Remarketing Revenue Bond | 46,000,000 | |||||||||||||||||||||
Georgia Power [Member] | Line of Credit [Member] | Debt Due 2029 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.488% | |||||||||||||||||||||
Georgia Power [Member] | Line of Credit [Member] | Debt Due Two Thousand Forty Four [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.86% | 3.072% | 3.283% | 3.072% | 3.002% | |||||||||||||||||
Georgia Power [Member] | Capital Lease Obligations [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.90% | 7.90% | 7.90% | |||||||||||||||||||
Georgia Power [Member] | Secured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term Debt | $ 2,400,000,000 | $ 2,400,000,000 | $ 1,200,000,000 | |||||||||||||||||||
Georgia Power [Member] | Senior Notes [Member] | Series 2015A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | $ 500,000,000 | ||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.95% | 1.95% | ||||||||||||||||||||
Georgia Power [Member] | Senior Notes [Member] | Series Z [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.25% | 5.25% | ||||||||||||||||||||
Georgia Power [Member] | Unsecured Debt [Member] | Series Z [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redemption Amount of Principal Notes | $ 250,000,000 | $ 250,000,000 | ||||||||||||||||||||
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 45.70% | |||||||||||||||||||||
Georgia Power [Member] | Vogtle Units Three and Four [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 45.70% | 45.70% | ||||||||||||||||||||
Mississippi Power and Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | ||||||||||||||||||||
Subsidiaries [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | $ 30,000,000 | $ 30,000,000 | 34,000,000 | |||||||||||||||||||
Subsidiaries [Member] | Capital Lease Obligations [Member] | Minimum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.20% | 1.20% | ||||||||||||||||||||
Subsidiaries [Member] | Capital Lease Obligations [Member] | Maximum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.10% | 3.10% | ||||||||||||||||||||
Southern Power and Traditional Operating Companies [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 3,100,000,000 | $ 3,100,000,000 | ||||||||||||||||||||
Southern Company [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Bank Loans | $ 400,000,000 | $ 400,000,000 | ||||||||||||||||||||
Bank Loans Period Of Extension | 18 months | |||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | $ 400,000,000 | |||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 70.00% | 70.00% | ||||||||||||||||||||
Senior Notes outstanding | $ 2,400,000,000 | $ 2,400,000,000 | 2,200,000,000 | |||||||||||||||||||
Unused credit with banks | 2,250,000,000 | 2,250,000,000 | ||||||||||||||||||||
Expires, 2020 | 1,250,000,000 | 1,250,000,000 | ||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,250,000,000 | $ 1,250,000,000 | $ 2,250,000,000 | $ 1,000,000,000 | ||||||||||||||||||
Southern Company [Member] | Junior Subordinated Debt [Member] | Series 2015A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 1,000,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 6.25% | |||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Temporary Equity, Shares Outstanding | shares | 334,210 | 334,210 | 334,210 | |||||||||||||||||||
Number Of Floating Rate Bank Loans | loan | 3 | |||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | $ 728,000,000 | $ 728,000,000 | $ 778,000,000 | |||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 301,000,000 | 375,000,000 | 301,000,000 | 0 | 0 | |||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 275,000,000 | |||||||||||||||||||||
Other Long-term Debt | 929,000,000 | 929,000,000 | 353,000,000 | |||||||||||||||||||
Senior notes, current | 300,000,000 | 300,000,000 | 0 | |||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2014 | 728,000,000 | 728,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 614,000,000 | 614,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 3,000,000 | 3,000,000 | ||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four | 128,000,000 | 128,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 10,000,000 | 10,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 300,000,000 | 300,000,000 | 300,000,000 | |||||||||||||||||||
Long-term debt maturities, 2018 | 125,000,000 | 125,000,000 | 125,000,000 | |||||||||||||||||||
Long-term debt maturities, 2017 | 35,000,000 | 35,000,000 | 35,000,000 | |||||||||||||||||||
Bank Loans | 900,000,000 | 900,000,000 | 775,000,000 | |||||||||||||||||||
Bank Loans Period Of Extension | 25 months | 18 months | ||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | $ 475,000,000 | |||||||||||||||||||||
Repayment Aggregate Principal Amount Of Floating Rate Bank Loan | $ 275,000,000 | |||||||||||||||||||||
Bank loans outstanding | 900,000,000 | 900,000,000 | ||||||||||||||||||||
Bank term loans | $ 425,000,000 | $ 425,000,000 | 775,000,000 | |||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | ||||||||||||||||||||
Senior Notes outstanding | $ 1,100,000,000 | $ 1,100,000,000 | 1,100,000,000 | |||||||||||||||||||
Pollution control revenue bonds, outstanding | 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 | 0 | 0 | 50,000,000 | |||||||||||||||||||
Other revenue bond obligation | 50,000,000 | 50,000,000 | 50,000,000 | |||||||||||||||||||
Period Of Nitrogen Supply Agreement | 20 years | |||||||||||||||||||||
Capitalized lease obligations | 77,000,000 | 77,000,000 | 79,000,000 | |||||||||||||||||||
Capital leases, due 2016 | 7,000,000 | 7,000,000 | ||||||||||||||||||||
Capital leases, due 2017 | 7,000,000 | 7,000,000 | ||||||||||||||||||||
Capital leases, due 2018 | 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 and thereafter | 7,000,000 | 7,000,000 | ||||||||||||||||||||
Deposit Liability, Current | $ 150,000,000 | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,262,000,000 | 1,262,000,000 | 1,173,000,000 | |||||||||||||||||||
Deposit Received | $ 75,000,000 | $ 50,000,000 | ||||||||||||||||||||
Return Of Interest Bearing Refundable Deposits Related to Assets Sale Plus Accrued Interest | $ 301,000,000 | |||||||||||||||||||||
Unused credit with banks | 195,000,000 | 195,000,000 | ||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | $ 40,000,000 | $ 40,000,000 | ||||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | 100.00% | ||||||||||||||||||||
Expires, 2020 | $ 0 | $ 0 | ||||||||||||||||||||
Short-term Debt | 500,000,000 | $ 500,000,000 | 0 | |||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 220,000,000 | $ 220,000,000 | ||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | $ 77,000,000 | $ 77,000,000 | $ 80,000,000 | |||||||||||||||||||
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Revenue bond obligations face value | 270,000,000 | |||||||||||||||||||||
Significant Acquisitions and Disposals, Acquisition Costs, Assumption of Debt, at Fair Value | 346,000,000 | |||||||||||||||||||||
Fair value adjustment at date of purchase | $ 76,000,000 | |||||||||||||||||||||
Mississippi Power [Member] | Maturity April First Two Thousand Sixteen [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Number Of Floating Rate Bank Loans | loan | 2 | |||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | $ 425,000,000 | |||||||||||||||||||||
Mississippi Power [Member] | Series 1999A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.13% | |||||||||||||||||||||
Mississippi Power [Member] | Promissory Note [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.50% | 1.50% | 1.25% | 1.50% | ||||||||||||||||||
Mississippi Power [Member] | Capital Lease Obligations [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.90% | 4.90% | 4.90% | |||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Redeemable preferred stock | $ 85,000,000 | $ 85,000,000 | $ 342,000,000 | |||||||||||||||||||
Debt Instrument, Term | 3 years | |||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 200,000,000 | $ 200,000,000 | 454,000,000 | |||||||||||||||||||
Senior Notes And Pollution Control Revenue Bonds, Current | 200,000,000 | 200,000,000 | 454,000,000 | |||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Proceeds from issuance of junior subordinated notes | 206,000,000 | 206,000,000 | 206,000,000 | |||||||||||||||||||
Other Long-term Debt | 1,097,000,000 | 1,097,000,000 | 1,151,000,000 | |||||||||||||||||||
Long-term debt maturities, 2015 | 0 | 0 | 400,000,000 | |||||||||||||||||||
Long-term debt maturities, 2016 | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||
Long-term debt maturities, 2018 | 200,000,000 | 200,000,000 | 200,000,000 | |||||||||||||||||||
Long-term debt maturities, 2019 | 250,000,000 | 250,000,000 | 250,000,000 | |||||||||||||||||||
Long-term debt maturities, 2017 | $ 525,000,000 | $ 525,000,000 | 525,000,000 | |||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | ||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 14.00% | 14.00% | ||||||||||||||||||||
Pollution control revenue bonds, outstanding | $ 1,100,000,000 | $ 1,100,000,000 | 1,200,000,000 | |||||||||||||||||||
Repayments of Senior Debt | 650,000,000 | 0 | $ 250,000,000 | |||||||||||||||||||
Capitalized lease obligations | 5,000,000 | 5,000,000 | 5,000,000 | |||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 8,736,000,000 | 8,736,000,000 | 8,522,000,000 | |||||||||||||||||||
Unused credit with banks | 1,340,000,000 | 1,340,000,000 | ||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 810,000,000 | 810,000,000 | ||||||||||||||||||||
Pollution Control Revenue Bonds Required To Be Remarketed | 80,000,000 | 80,000,000 | ||||||||||||||||||||
Short-term debt outstanding, regulatory approved maximum | 2,100,000,000 | 2,100,000,000 | ||||||||||||||||||||
Expires, 2020 | 800,000,000 | 800,000,000 | ||||||||||||||||||||
Short-term Debt | 0 | $ 0 | 0 | |||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.10% | |||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,340,000,000 | $ 1,340,000,000 | ||||||||||||||||||||
Temporary Equity, Other Changes | 5,000,000 | |||||||||||||||||||||
Alabama Power [Member] | Natural Gas Pipeline [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | 5,000,000 | 5,000,000 | 5,000,000 | |||||||||||||||||||
Alabama Power [Member] | Series 2014DD [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.65% | |||||||||||||||||||||
Alabama Power [Member] | Trust Preferred Securities Subject to Mandatory Redemption [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Preferred securities, outstanding | 200,000,000 | 200,000,000 | $ 200,000,000 | |||||||||||||||||||
Alabama Power [Member] | Senior Notes And Pollution Control Bond [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term debt maturities, 2015 | 200,000,000 | 200,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 562,000,000 | 562,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2018 | 201,000,000 | 201,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2019 | 251,000,000 | 251,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2017 | $ 0 | $ 0 | ||||||||||||||||||||
Alabama Power [Member] | Series 2007B [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Remarketing Revenue Bond | 80,000,000 | |||||||||||||||||||||
Alabama Power [Member] | Series FF [Member] | Subsequent Event [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.20% | |||||||||||||||||||||
Alabama Power [Member] | Capital Lease Obligations [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 6.90% | 6.90% | 6.90% | |||||||||||||||||||
Alabama Power [Member] | Senior Notes [Member] | Series 2015A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 175,000,000 | $ 550,000,000 | ||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.75% | 3.75% | ||||||||||||||||||||
Alabama Power [Member] | Senior Notes [Member] | Series 2015B [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 250,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 2.80% | |||||||||||||||||||||
Alabama Power [Member] | Senior Notes [Member] | Series 2016A [Member] | Subsequent Event [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 400,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.30% | |||||||||||||||||||||
Alabama Power [Member] | Unsecured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redemption Amount of Principal Notes | $ 250,000,000 | |||||||||||||||||||||
Senior Notes outstanding | $ 5,600,000,000 | $ 5,600,000,000 | $ 5,300,000,000 | |||||||||||||||||||
Alabama Power [Member] | Unsecured Debt [Member] | Series FF [Member] | Subsequent Event [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redemption Amount of Principal Notes | $ 200,000,000 | |||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 403,000,000 | 403,000,000 | 525,000,000 | |||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Prepayment of debt | 4,000,000 | |||||||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 34,000,000 | 34,000,000 | 12,000,000 | |||||||||||||||||||
Other Long-term Debt | 13,000,000 | 13,000,000 | 19,000,000 | |||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 500,000,000 | 500,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 350,000,000 | 350,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 300,000,000 | 300,000,000 | ||||||||||||||||||||
Bank Loans | $ 400,000,000 | $ 400,000,000 | ||||||||||||||||||||
Bank Loans Period Of Extension | 13 months | |||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | $ 400,000,000 | |||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | ||||||||||||||||||||
Line of Credit Facility, Amount Outstanding | 0 | |||||||||||||||||||||
Senior Notes outstanding | $ 2,700,000,000 | $ 2,700,000,000 | 1,600,000,000 | |||||||||||||||||||
Repayments of Senior Debt | 525,000,000 | 0 | $ 0 | |||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,248,000,000 | 1,248,000,000 | 1,035,000,000 | |||||||||||||||||||
Unused credit with banks | 566,000,000 | 566,000,000 | 488,000,000 | |||||||||||||||||||
Expires, 2020 | 600,000,000 | 600,000,000 | ||||||||||||||||||||
Short-term Debt | 137,000,000 | $ 137,000,000 | 195,000,000 | |||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 600,000,000 | $ 600,000,000 | $ 600,000,000 | 500,000,000 | ||||||||||||||||||
Southern Power [Member] | Senior Notes, Current [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Long-term Debt and Capital Lease Obligations, Current | 400,000,000 | 400,000,000 | 525,000,000 | |||||||||||||||||||
Southern Power [Member] | Notes Payable to TRE [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Other Long-term Debt | $ 3,000,000 | $ 3,000,000 | ||||||||||||||||||||
Southern Power [Member] | Floating Rate Bank Loan [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | 65.00% | ||||||||||||||||||||
Southern Power [Member] | Senior Notes [Member] | Series 2015A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 350,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.50% | |||||||||||||||||||||
Southern Power [Member] | Senior Notes [Member] | Series 2015B [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 300,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 2.375% | |||||||||||||||||||||
Southern Power [Member] | Senior Notes [Member] | Series Two Thousand Three [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.875% | |||||||||||||||||||||
Repayments of Senior Debt | $ 525,000,000 | |||||||||||||||||||||
Southern Power [Member] | Senior Notes [Member] | Series 2015C [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.15% | |||||||||||||||||||||
Southern Power [Member] | Senior Notes [Member] | Series 2015D [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.85% | |||||||||||||||||||||
Southern Company And Subsidiaries [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 3,700,000,000 | $ 3,700,000,000 | ||||||||||||||||||||
Traditional Operating Companies [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 3,300,000,000 | 3,300,000,000 | 3,200,000,000 | |||||||||||||||||||
Notes due September 30, 2032 [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 2,000,000 | |||||||||||||||||||||
Capital Lease Obligations [Member] | Georgia Power [Member] | Secured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term Debt | 2,200,000,000 | 2,200,000,000 | ||||||||||||||||||||
Scenario, Plan [Member] | Bridge Agreement [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 8,100,000,000 | $ 8,100,000,000 | ||||||||||||||||||||
Period After Funding That Loan Will Mature And Be Payable in Full | 364 days | |||||||||||||||||||||
5.20% Class A Preferred Stock [Member] | Alabama Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Temporary Equity, Shares Outstanding | shares | 6,480,000 | |||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Temporary Equity, Dividend Rate Percentage | 0.052 | 0.0520 | ||||||||||||||||||||
Temporary Equity, Par or Stated Value Per Share | $ / shares | $ 25 | |||||||||||||||||||||
5.20% Class A Preferred Stock [Member] | Alabama Power [Member] | Aggregate Stated Capital [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 162,000,000 | |||||||||||||||||||||
5.30% Class A Preferred Stock [Member] | Alabama Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Temporary Equity, Shares Outstanding | shares | 4,000,000 | |||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Temporary Equity, Dividend Rate Percentage | 0.053 | 0.0530 | ||||||||||||||||||||
Temporary Equity, Par or Stated Value Per Share | $ / shares | $ 25 | |||||||||||||||||||||
5.30% Class A Preferred Stock [Member] | Alabama Power [Member] | Aggregate Stated Capital [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 100,000,000 | |||||||||||||||||||||
5.625% Preference Stock [Member] | Alabama Power [Member] | ||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||
Temporary Equity, Shares Outstanding | shares | 6,000,000 | |||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Temporary Equity, Dividend Rate Percentage | 0.05625 | 0.05625 | ||||||||||||||||||||
5.625% Preference Stock [Member] | Alabama Power [Member] | Aggregate Stated Capital [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | $ 150,000,000 | |||||||||||||||||||||
Commercial Paper [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Short Term Borrowings Excluding Other Energy Service Contracts | 740,000,000 | $ 740,000,000 | 803,000,000 | |||||||||||||||||||
Commercial Paper [Member] | Gulf Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Short Term Borrowings Excluding Other Energy Service Contracts | 142,000,000 | 142,000,000 | 110,000,000 | |||||||||||||||||||
Commercial Paper [Member] | Georgia Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Short Term Borrowings Excluding Other Energy Service Contracts | 158,000,000 | 158,000,000 | 156,000,000 | |||||||||||||||||||
Commercial Paper [Member] | Mississippi Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Short Term Borrowings Excluding Other Energy Service Contracts | 0 | 0 | 0 | |||||||||||||||||||
Commercial Paper [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Short Term Borrowings Excluding Other Energy Service Contracts | 0 | 0 | $ 195,000,000 | |||||||||||||||||||
Long-term Debt [Member] | Southern Company [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Bank Loans | 1,230,000,000 | 1,230,000,000 | ||||||||||||||||||||
Short-term Debt [Member] | Southern Company [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Bank Loans | 475,000,000 | 475,000,000 | ||||||||||||||||||||
Power Purchase Agreement [Member] | Georgia Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capital Leased Assets, Gross | 149,000,000 | 149,000,000 | ||||||||||||||||||||
Capitalized lease obligations | $ 148,000,000 | $ 148,000,000 | ||||||||||||||||||||
Capital Leased Assets, Number of Units | leased_asset_units | 2 | 2 | ||||||||||||||||||||
Debt Instrument, Interest Amount | $ 20,000,000 | $ 20,000,000 | ||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 10,000,000 | $ 10,000,000 | ||||||||||||||||||||
Power Purchase Agreement [Member] | Georgia Power [Member] | Minimum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 13.00% | 13.00% | ||||||||||||||||||||
Power Purchase Agreement [Member] | Georgia Power [Member] | Maximum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 14.00% | 14.00% | ||||||||||||||||||||
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 137,000,000 | $ 137,000,000 | ||||||||||||||||||||
Unused credit with banks | 758,000,000 | 758,000,000 | ||||||||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 895,000,000 | $ 895,000,000 | ||||||||||||||||||||
Debt, Weighted Average Interest Rate | 2.00% | 2.00% |
Commitments - Estimated Long-te
Commitments - Estimated Long-term obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2013 | |
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | $ 121 | |
2,017 | 103 | |
2,018 | 81 | |
2,019 | 61 | |
2,020 | 53 | |
2021 and thereafter | 706 | |
Total | 1,125 | |
Alabama Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 19 | |
2,017 | 13 | |
2,018 | 9 | |
2,019 | 9 | |
2,020 | 9 | |
2021 and thereafter | 13 | |
Total | 72 | |
Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 23 | |
2,017 | 18 | |
2,018 | 12 | |
2,019 | 8 | |
2,020 | 7 | |
2021 and thereafter | 16 | |
Total | 84 | |
2,016 | 246 | |
2,017 | 224 | |
2,018 | 217 | |
2,019 | 221 | |
2,020 | 214 | |
2021 and thereafter | 1,819 | |
Total | 2,941 | |
Minimum Lease Payments, Capital Leases [Abstract] | ||
Capital Leases, Future Minimum Payments, Lesser Of Fair Value and Present Value | $ 149 | |
Period Of Service For Gas Transportation Supplier | 1 year | |
Gulf Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | $ 10 | |
2,017 | 7 | |
2,018 | 4 | |
Total | 21 | |
Railcars [Member] | Alabama Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 13 | |
2,017 | 8 | |
2,018 | 5 | |
2,019 | 5 | |
2,020 | 5 | |
2021 and thereafter | 13 | |
Total | 49 | |
Vehicles And Other [Member] | Alabama Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 6 | |
2,017 | 5 | |
2,018 | 4 | |
2,019 | 4 | |
2,020 | 4 | |
2021 and thereafter | 0 | |
Total | 23 | |
Barges and Rail Cars [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 40 | |
2,017 | 25 | |
2,018 | 14 | |
2,019 | 6 | |
2,020 | 6 | |
2021 and thereafter | 16 | |
Total | 107 | |
Barges and Rail Cars [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 15 | |
2,017 | 10 | |
2,018 | 5 | |
2,019 | 1 | |
2,020 | 1 | |
2021 and thereafter | 3 | |
Total | 35 | |
Barges and Rail Cars [Member] | Gulf Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 9 | |
2,017 | 6 | |
2,018 | 4 | |
Total | 19 | |
Other Lease Payments [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 81 | |
2,017 | 78 | |
2,018 | 67 | |
2,019 | 55 | |
2,020 | 47 | |
2021 and thereafter | 690 | |
Total | 1,018 | |
Other Lease Payments [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 8 | |
2,017 | 8 | |
2,018 | 7 | |
2,019 | 7 | |
2,020 | 6 | |
2021 and thereafter | 13 | |
Total | 49 | |
Other Lease Payments [Member] | Gulf Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 1 | |
2,017 | 1 | |
2,018 | 0 | |
Total | 2 | |
Purchased Power [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,016 | 233 | |
2,017 | 242 | |
2,018 | 246 | |
2,019 | 249 | |
2,020 | 246 | |
2021 and thereafter | 1,291 | |
Total | 2,507 | |
Purchased Power [Member] | Alabama Power [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,016 | 39 | |
2,017 | 40 | |
2,018 | 41 | |
2,019 | 43 | |
2,020 | 44 | |
2021 and thereafter | 93 | |
Total | 300 | |
Purchased Power [Member] | Gulf Power [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,016 | 79 | |
2,017 | 79 | |
2,018 | 79 | |
2,019 | 79 | |
2,020 | 79 | |
2021 and thereafter | 191 | |
Total | 586 | |
Other Lease Payments [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,016 | 10 | |
2,017 | 8 | |
2,018 | 7 | |
2,019 | 8 | |
2,020 | 4 | |
2021 and thereafter | 47 | |
Total | 84 | |
Affiliate Capital Lease PPA [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Capital Leases [Abstract] | ||
2,016 | 22 | |
2,017 | 22 | |
2,018 | 22 | |
2,019 | 23 | |
2,020 | 23 | |
2021 and thereafter | 227 | |
Total | 339 | |
Less: amounts representing executory costs | 54 | |
Net minimum lease payments | 285 | |
Less: amounts representing interest | 84 | |
Present value of net minimum lease payments | 201 | |
Affiliate Operating Lease PPA [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 99 | |
2,017 | 71 | |
2,018 | 62 | |
2,019 | 63 | |
2,020 | 64 | |
2021 and thereafter | 538 | |
Total | 897 | |
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 115 | |
2,017 | 123 | |
2,018 | 126 | |
2,019 | 127 | |
2,020 | 123 | |
2021 and thereafter | 1,007 | |
Total | 1,621 | |
Minimum Lease Payments, Capital Leases [Abstract] | ||
Biomass PPAs Amount | 304 | |
Plant Vogtle Units 1 and 2 [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2,016 | 10 | |
2,017 | 8 | |
2,018 | 7 | |
2,019 | 8 | |
2,020 | 4 | |
2021 and thereafter | 47 | |
Total | $ 84 | |
Plant McIntosh [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Capital Leases [Abstract] | ||
Period Of Service For Gas Transportation Supplier | 15 years |
Commitments (Details)
Commitments (Details) | 12 Months Ended | |||
Dec. 31, 2015USD ($)Railcar | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | |
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | $ 4,750,000,000 | $ 6,005,000,000 | $ 5,510,000,000 | |
Expense Under Purchase Power Agreements Accounted For As Operating Leases | 227,000,000 | 198,000,000 | 157,000,000 | |
Operating Leases, Rent Expense | 130,000,000 | 118,000,000 | 123,000,000 | |
Leasing commitment, 2017 | 103,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 81,000,000 | |||
Leasing commitment, 2019 | 61,000,000 | |||
Leasing commitment, 2020 | 53,000,000 | |||
Leasing commitment, 2021 and thereafter | 706,000,000 | |||
Operating leases, future minimum lease payments due | 1,125,000,000 | |||
Senior Notes | 19,100,000,000 | 18,200,000,000 | ||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 121,000,000 | |||
Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2017 | 25,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 14,000,000 | |||
Leasing commitment, 2019 | 6,000,000 | |||
Leasing commitment, 2020 | 6,000,000 | |||
Leasing commitment, 2021 and thereafter | 16,000,000 | |||
Operating leases, future minimum lease payments due | 107,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 40,000,000 | |||
Alabama Power and Georgia Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating leases, future minimum lease payments due | 48,000,000 | |||
Alabama Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 1,342,000,000 | 1,605,000,000 | 1,631,000,000 | |
Expense Under Purchase Power Agreements Accounted For As Operating Leases | $ 38,000,000 | 37,000,000 | 30,000,000 | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 14.00% | |||
Operating Leases, Rent Expense | $ 19,000,000 | 18,000,000 | 21,000,000 | |
Leasing commitment, 2017 | 13,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 9,000,000 | |||
Leasing commitment, 2019 | 9,000,000 | |||
Leasing commitment, 2020 | 9,000,000 | |||
Leasing commitment, 2021 and thereafter | 13,000,000 | |||
Operating leases, future minimum lease payments due | 72,000,000 | |||
Long-term pollution control bonds | 1,100,000,000 | 1,200,000,000 | ||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 19,000,000 | |||
Alabama Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating Leases, Rent Expense | 13,000,000 | 14,000,000 | 18,000,000 | |
Alabama Power [Member] | Residual Value, Leased Property [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2017 | 0 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 0 | |||
Leasing commitment, 2019 | 0 | |||
Leasing commitment, 2020 | 0 | |||
Leasing commitment, 2021 and thereafter | 12,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 4,000,000 | |||
Georgia Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Capital Leases, Future Minimum Payments, Lesser Of Fair Value and Present Value | 149,000,000 | |||
Fuel expense | 2,033,000,000 | 2,547,000,000 | 2,307,000,000 | |
Capacity Payments | 10,000,000 | 19,000,000 | 27,000,000 | |
Deferred capacity expense | 203,000,000 | 167,000,000 | 162,000,000 | |
Operating Leases, Rent Expense | $ 29,000,000 | 28,000,000 | $ 32,000,000 | |
Percentage Of Minimum Lease Payments | 100.00% | |||
Leasing commitment, 2017 | $ 18,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 12,000,000 | |||
Leasing commitment, 2019 | 8,000,000 | |||
Leasing commitment, 2020 | 7,000,000 | |||
Leasing commitment, 2021 and thereafter | 16,000,000 | |||
Operating leases, future minimum lease payments due | 84,000,000 | |||
Long-term pollution control bonds | 1,800,000,000 | 1,600,000,000 | ||
Senior Notes | $ 6,300,000,000 | 6,900,000,000 | ||
Period Of Service For Gas Transportation Supplier | 1 year | |||
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 43,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $ 23,000,000 | |||
Georgia Power [Member] | Plant McIntosh [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Period Of Service For Gas Transportation Supplier | 15 years | |||
Georgia Power [Member] | MEAG Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 5.00% | |||
Georgia Power [Member] | Alabama Power [Member] | Payment Guarantee [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Long-term pollution control bonds | $ 25,000,000 | |||
Georgia Power [Member] | Alabama Power [Member] | Financial Guarantee [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Senior Notes | 100,000,000 | |||
Georgia Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2017 | 10,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 5,000,000 | |||
Leasing commitment, 2019 | 1,000,000 | |||
Leasing commitment, 2020 | 1,000,000 | |||
Leasing commitment, 2021 and thereafter | 3,000,000 | |||
Operating leases, future minimum lease payments due | 35,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 15,000,000 | |||
Georgia Power [Member] | Residual Value, Leased Property [Member] | 2018 [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating leases, future minimum lease payments due | 32,000,000 | |||
Gulf Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 445,000,000 | 605,000,000 | $ 533,000,000 | |
Expense Under Purchase Power Agreements Accounted For As Operating Leases | 75,000,000 | 50,000,000 | 21,000,000 | |
Deferred capacity expense | 141,000,000 | 163,000,000 | ||
Operating Leases, Rent Expense | 14,000,000 | 15,000,000 | 18,000,000 | |
Leasing commitment, 2017 | 7,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 4,000,000 | |||
Operating leases, future minimum lease payments due | 21,000,000 | |||
Long-term pollution control bonds | 309,000,000 | 309,000,000 | ||
Senior Notes | 1,010,000,000 | 1,070,000,000 | ||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 10,000,000 | |||
Gulf Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2017 | 6,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 4,000,000 | |||
Operating leases, future minimum lease payments due | 19,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 9,000,000 | |||
Gulf Power [Member] | Barges and Rail Cars [Member] | Plant Daniel [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel cost recovery clause | 2,000,000 | 3,000,000 | 3,000,000 | |
Leasing commitment, 2017 | 1,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 1,000,000 | |||
Gulf Power [Member] | Barge Transportation [Member] | Plant Crist and Plant Smith [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel cost recovery clause | 10,000,000 | 10,000,000 | 12,000,000 | |
Leasing commitment, 2017 | 5,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 5,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 5,000,000 | |||
Mississippi Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | $ 443,000,000 | 574,000,000 | 491,000,000 | |
Term of Management Fee Contract | 40 years | |||
Management fee | $ 38,000,000 | |||
Operating Leases, Rent Expense | $ 5,000,000 | 10,000,000 | 10,000,000 | |
Number of Railcars Used Under Operating Lease | Railcar | 229 | |||
Company's share of the leases | 50.00% | |||
Fuel cost recovery clause | $ 2,000,000 | 3,000,000 | 3,000,000 | |
Long-term pollution control bonds | 83,000,000 | 83,000,000 | ||
Senior Notes | $ 1,100,000,000 | 1,100,000,000 | ||
Mississippi Power [Member] | Plant Daniel [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Company's share of the leases | 50.00% | |||
Mississippi Power [Member] | Plant Watson [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Company's share of the leases | 100.00% | |||
Mississippi Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Average leasing commitment, 2015 | $ 1,000,000 | |||
Average leasing commitment, 2016 | 0 | |||
Average leasing commitment, 2017 | 0 | |||
Mississippi Power [Member] | Fuel Handling Equipment [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating Leases, Rent Expense | 200,000 | 200,000 | ||
Mississippi Power [Member] | Barge Transportation [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating Leases, Rent Expense | 2,000,000 | 8,000,000 | 7,000,000 | |
Southern Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 441,000,000 | 596,000,000 | 474,000,000 | |
Operating Leases, Rent Expense | 7,000,000 | 4,000,000 | 2,000,000 | |
Leasing commitment, 2017 | 12,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 12,000,000 | |||
Leasing commitment, 2019 | 12,000,000 | |||
Leasing commitment, 2020 | 13,000,000 | |||
Leasing commitment, 2021 and thereafter | 595,000,000 | |||
Senior Notes | 2,700,000,000 | 1,600,000,000 | ||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 11,000,000 | |||
Redeemable Put Option | 43,000,000 | $ 39,000,000 | $ 29,000,000 | $ 8,000,000 |
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Biomass PPAs Amount | 304,000,000 | |||
Leasing commitment, 2017 | 123,000,000 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 126,000,000 | |||
Leasing commitment, 2019 | 127,000,000 | |||
Leasing commitment, 2020 | 123,000,000 | |||
Leasing commitment, 2021 and thereafter | 1,007,000,000 | |||
Operating leases, future minimum lease payments due | 1,621,000,000 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $ 115,000,000 |
Common Stock and Stock Compen84
Common Stock and Stock Compensation - Stock Options, Assumptions Used (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted | |||
Expected volatility | 14.60% | 16.60% | |
Expected term (in years) | 5 years | 5 years | |
Interest rate | 1.50% | 0.90% | |
Dividend yield, percentage | 4.90% | 4.40% | |
Weighted average grant-date fair value (in dollars per share) | $ 2.20 | $ 2.93 | |
Performance Shares [Member] | |||
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted | |||
Expected volatility | 12.90% | 12.60% | 12.00% |
Expected term (in years) | 3 years | 3 years | 3 years |
Interest rate | 1.00% | 0.60% | 0.40% |
Dividend yield | $ 2.03 | $ 1.96 | |
Weighted average grant-date fair value (in dollars per share) | $ 46.38 | $ 37.54 | $ 40.50 |
Common Stock and Stock Compen85
Common Stock and Stock Compensation - Stock Option Activity (Details) | 12 Months Ended |
Dec. 31, 2015$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Shares Subject to Option, Outstanding, Beginning Balance | shares | 39,929,319 |
Shares Subject to Option, Exercised | shares | 4,032,729 |
Shares Subject to Options, Cancelled | shares | 146,684 |
Shares Subject to Option, Outstanding, Ending Balance | shares | 35,749,906 |
Shares Subject to Options, Exercisable, Ending Balance | shares | 25,857,590 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | |
Options Outstanding, Weighted Average Exercise Price, Beginning of Period (in dollars per share) | $ / shares | $ 40.55 |
Options Exercised, Weighted Average Exercise Price (in dollars per share) | $ / shares | 36.84 |
Options Cancelled, Weighted Average Exercise Price (in dollars per share) | $ / shares | 42.31 |
Options Outstanding, Weighted Average Exercise Price, End of Period (in dollars per share) | $ / shares | 40.96 |
Options Exercisable, Weighted Average Exercise Price, End of Period (in dollars per share) | $ / shares | $ 40.53 |
Common Stock and Stock Compen86
Common Stock and Stock Compensation - Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Earnings per share (EPS) — | |||
As reported shares | 910 | 897 | 877 |
Effect of options | 4 | 4 | 4 |
Diluted shares | 914 | 901 | 881 |
Common Stock and Stock Compen87
Common Stock and Stock Compensation - Textual (Details) $ / shares in Units, $ in Millions | Mar. 02, 2015shares | Dec. 31, 2015USD ($)Employeeshare_unit_type$ / sharesshares | Dec. 31, 2014USD ($)$ / sharesshares | Dec. 31, 2013USD ($)$ / sharesshares |
Share-based Compensation [Abstract] | ||||
Stock Issued During Period, Shares, Southern Investment Plan and employee and director stock plans | shares | 6,600,000 | |||
Stock Issued During Period, Value, Southern Investment Plan and employee and director stock plans | $ 256 | |||
Stock Repurchased During Period, Shares | shares | 2,600,000 | |||
Stock Repurchased During Period, Value | $ 115 | |||
Share-based compensation arrangement by Share-based payment award, number of shares reserved for issuance, pursuant to Stock-based compensation plan | shares | 106,000,000 | |||
Number Of Employees Participating in Stock Option and Performance Share Units Program | Employee | 5,405 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 2.20 | $ 2.93 | ||
Weighted average remaining contractual term for options outstanding | 6 years | |||
Aggregate intrinsic value for options outstanding | $ 209 | |||
Aggregate intrinsic value for options exercisable | 162 | |||
Total compensation cost for award recognized in income | 6 | $ 27 | $ 25 | |
Total compensation cost for award recognized in income, tax benefit | 2 | 10 | 10 | |
Total intrinsic value of options exercised | 48 | 125 | 77 | |
Actual tax benefit for the tax deduction from stock option exercised | 19 | 48 | 30 | |
Cash received from issuance related to option exercise | $ 154 | $ 400 | $ 204 | |
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% | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 6 years | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares) | shares | 1,000,000 | 7,000,000 | ||
Undistributed retained earnings of the subsidiaries | $ 7,000 | |||
Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 46.38 | $ 37.54 | $ 40.50 | |
Total unrecognized compensation cost related to award | $ 33 | |||
Total unrecognized compensation cost related to award, weighted average period | 19 months | |||
Total compensation cost for award recognized in income | $ 88 | $ 33 | $ 31 | |
Total compensation cost for award recognized in income, tax benefit | $ 34 | $ 13 | 12 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Performance share units, unvested | shares | 2,480,392 | 1,830,381 | ||
Performance share units, granted | shares | 1,542,653 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period (in shares) | shares | 812,740 | |||
Performance unit shares, forfeited | shares | 79,902 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number (in shares) | shares | 227,515 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price (in dollars per share) | $ / shares | $ 46.80 | |||
Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
EPS-based and ROE-based Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Additional Types Of Performance Share Units | share_unit_type | 2 | |||
Initial Assumed Percentage Payout At End Of Performance Period | 100.00% | |||
ROE-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
TSR-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 50.00% | |||
EPS-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Maximum [Member] | ||||
Share-based Compensation [Abstract] | ||||
Stock Repurchase Program, Remaining Number of Shares Authorized to be Repurchased | shares | 20,000,000 | |||
Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Southern Company Common Stock [Member] | ||||
Share-based Compensation [Abstract] | ||||
Remaining shares available for awards | shares | 14,000,000 | |||
Alabama Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Employees Participating in Stock Option and Performance Share Units Program | Employee | 881 | |||
Aggregate intrinsic value for options outstanding | $ 33 | |||
Aggregate intrinsic value for options exercisable | 26 | |||
Total intrinsic value of options exercised | 8 | $ 21 | 11 | |
Actual tax benefit for the tax deduction from stock option exercised | 3 | 8 | 4 | |
Alabama Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | $ 4 | |||
Total unrecognized compensation cost related to award, weighted average period | 19 months | |||
Total compensation cost for award recognized in income | $ 13 | 5 | 5 | |
Total compensation cost for award recognized in income, tax benefit | $ 5 | $ 2 | $ 2 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Performance share units, granted | shares | 214,709 | 176,070 | 141,355 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 46.42 | $ 37.54 | $ 40.50 | |
Alabama Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | shares | 2,027,298 | 1,319,038 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 2.20 | $ 2.93 | ||
Alabama Power [Member] | EPS-based and ROE-based Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Additional Types Of Performance Share Units | share_unit_type | 2 | |||
Initial Assumed Percentage Payout At End Of Performance Period | 100.00% | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 47.78 | |||
Alabama Power [Member] | ROE-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Alabama Power [Member] | TSR-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 50.00% | |||
Alabama Power [Member] | EPS-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Alabama Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Georgia Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Employees Participating in Stock Option and Performance Share Units Program | Employee | 1,002 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | shares | 2,034,150 | 1,509,662 | ||
Aggregate intrinsic value for options outstanding | $ 45 | |||
Aggregate intrinsic value for options exercisable | 38 | |||
Total intrinsic value of options exercised | 9 | $ 19 | $ 16 | |
Actual tax benefit for the tax deduction from stock option exercised | $ 4 | 7 | 6 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Georgia Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | $ 4 | |||
Total unrecognized compensation cost related to award, weighted average period | 19 months | |||
Total compensation cost for award recognized in income | $ 15 | 6 | 6 | |
Total compensation cost for award recognized in income, tax benefit | $ 6 | $ 2 | $ 2 | |
Performance share units, granted | shares | 236,804 | 176,224 | 161,240 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 46.41 | $ 37.54 | $ 40.50 | |
Georgia Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 2.20 | $ 2.93 | ||
Georgia Power [Member] | EPS-based and ROE-based Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Additional Types Of Performance Share Units | share_unit_type | 2 | |||
Initial Assumed Percentage Payout At End Of Performance Period | 100.00% | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 47.78 | |||
Georgia Power [Member] | ROE-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Georgia Power [Member] | TSR-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 50.00% | |||
Georgia Power [Member] | EPS-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Georgia Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Gulf Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Employees Participating in Stock Option and Performance Share Units Program | Employee | 198 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | shares | 432,371 | 285,209 | ||
Share Based Compensation Arrangement by Share Based Payment Award Fair Value Assumptions Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 2.20 | $ 2.93 | ||
Aggregate intrinsic value for options outstanding | $ 7 | |||
Aggregate intrinsic value for options exercisable | 5 | |||
Total intrinsic value of options exercised | 2 | $ 5 | $ 2 | |
Actual tax benefit for the tax deduction from stock option exercised | $ 1 | $ 2 | $ 1 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Gulf Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Fair Value Assumptions Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 46.38 | $ 37.54 | $ 40.50 | |
Total unrecognized compensation cost related to award | $ 2 | |||
Total unrecognized compensation cost related to award, weighted average period | 19 months | |||
Total compensation cost for award recognized in income | $ 2 | $ 1 | $ 1 | |
Total compensation cost for award recognized in income, tax benefit | $ 1 | |||
Performance share units, granted | shares | 48,962 | 37,829 | 30,627 | |
Gulf Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Gulf Power [Member] | EPS-based and ROE-based Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Additional Types Of Performance Share Units | share_unit_type | 2 | |||
Initial Assumed Percentage Payout At End Of Performance Period | 100.00% | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 47.75 | |||
Gulf Power [Member] | ROE-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Gulf Power [Member] | TSR-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 50.00% | |||
Gulf Power [Member] | EPS-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Gulf Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Mississippi Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Employees Participating in Stock Option and Performance Share Units Program | Employee | 231 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | shares | 578,256 | 345,830 | ||
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Mississippi Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | $ 1 | |||
Total unrecognized compensation cost related to award, weighted average period | 19 months | |||
Total compensation cost for award recognized in income | $ 4 | $ 2 | $ 2 | |
Total compensation cost for award recognized in income, tax benefit | $ 2 | $ 1 | $ 1 | |
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Performance share units, granted | shares | 53,909 | 49,579 | 36,769 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 46.41 | $ 37.54 | $ 40.50 | |
Mississippi Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 2.20 | $ 2.93 | ||
Aggregate intrinsic value for options outstanding | $ 7 | |||
Aggregate intrinsic value for options exercisable | 5 | |||
Total intrinsic value of options exercised | 3 | $ 5 | $ 3 | |
Actual tax benefit for the tax deduction from stock option exercised | $ 1 | $ 2 | $ 1 | |
Mississippi Power [Member] | EPS-based and ROE-based Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number Of Additional Types Of Performance Share Units | share_unit_type | 2 | |||
Initial Assumed Percentage Payout At End Of Performance Period | 100.00% | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares | $ 47.77 | |||
Mississippi Power [Member] | ROE-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Mississippi Power [Member] | TSR-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 50.00% | |||
Mississippi Power [Member] | EPS-based Portion Of The Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Percentage Of Total Performance Share Units Granted | 25.00% | |||
Mississippi Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Parent [Member] | ||||
Share-based Compensation [Abstract] | ||||
Stock Repurchased During Period, Value | $ 115 |
Nuclear Insurance (Details)
Nuclear Insurance (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Apr. 30, 2014 | Dec. 31, 2015 | |
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act | $ 13,500 | |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375 | |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127 | |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | $ 19 | |
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 | |
Approximate period over which maximum per occurrence per unit limit is exhausted | 3 years | |
Aggregate payment for claims resulting from terrorist acts in one year period | $ 3,200 | |
Vogtle Units 3 and 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum limits for accidental property damage occurring during construction | 2,750 | |
Alabama Power [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act | 13,500 | |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375 | |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127 | |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | 19 | |
Maximum assessment, excluding any applicable state premium taxes | 255 | |
Maximum aggregate amount to be paid in one year | $ 38 | |
Block period considered for inflation adjustment against maximum assessment per reactor | 5 years | |
Maximum property damage insurance provided to nuclear generating facilities | $ 1,500 | |
Maximum additional coverage provided for losses under excess insurance | 1,250 | |
Maximum Sublimit Non-Nuclear Losses | $ 750 | |
Maximum Deductible Waiting Period Days | 182 days | |
Maximum coverage per occurrence per unit limit to obtain replacement power | $ 490 | |
Current maximum annual assessments under NEIL policies | 55 | |
Aggregate payment for claims resulting from terrorist acts in one year period | $ 3,200 | |
Elected Deductible Waiting Period, Days | 84 days | |
Georgia Power [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act | $ 13,500 | |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375 | |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127 | |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | 19 | |
Maximum assessment, excluding any applicable state premium taxes | 247 | |
Maximum aggregate amount to be paid in one year | $ 37 | |
Block period considered for inflation adjustment against maximum assessment per reactor | 5 years | |
Block period considered for inflation adjustment against maximum yearly assessment | 5 years | |
Maximum property damage insurance provided to nuclear generating facilities | $ 1,500 | |
Maximum additional coverage provided for losses under excess insurance | 1,250 | |
Maximum Sublimit Non-Nuclear Losses | $ 750 | |
Maximum deductible waiting period | 26 weeks | |
Maximum coverage per occurrence per unit limit to obtain replacement power | $ 490 | |
Approximate period over which maximum per occurrence per unit limit is exhausted | 3 years | |
Elected deductible waiting period | 12-week | |
Current maximum annual assessments under NEIL policies | $ 84 | |
Aggregate payment for claims resulting from terrorist acts in one year period | 3,200 | |
Georgia Power [Member] | Vogtle Units 3 and 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum limits for accidental property damage occurring during construction | 2,750 | |
Alabama Power and Georgia Power [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum property damage insurance provided to nuclear generating facilities | 1,500 | |
Maximum additional coverage provided for losses under excess insurance | $ 750 | $ 1,250 |
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, 2015 | Dec. 31, 2014 |
Assets: | ||
Asset Derivatives | $ 29 | $ 21 |
Liabilities: | ||
Liability Derivatives | 250 | 225 |
Fair Value, Measurements, Recurring [Member] | ||
Assets: | ||
Interest Rate Derivative Assets, at Fair Value | 22 | 8 |
Nuclear decommissioning trusts: | ||
Cash equivalents | 790 | 397 |
Other investments | 10 | 10 |
Fair value assets, total | 2,338 | 1,971 |
Liabilities: | ||
Liability Derivatives | 250 | |
Interest rate derivatives | 24 | |
Fair value liabilities, total | 225 | |
Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 610 | 668 |
Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 207 | 218 |
Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 152 | 130 |
Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 64 | 62 |
Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 289 | 299 |
Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 145 | 139 |
Fair Value, Measurements, Recurring [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 17 | 3 |
Fair Value, Measurements, Recurring [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 25 | 24 |
Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 7 | 13 |
Liabilities: | ||
Liability Derivatives | 220 | 201 |
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 30 | |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Assets: | ||
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Nuclear decommissioning trusts: | ||
Cash equivalents | 790 | 397 |
Other investments | 9 | 9 |
Fair value assets, total | 1,414 | 1,034 |
Liabilities: | ||
Liability Derivatives | 0 | |
Interest rate derivatives | 0 | |
Fair value liabilities, total | 0 | |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 541 | 583 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 47 | 34 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 11 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 16 | 11 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Interest Rate Derivative Assets, at Fair Value | 22 | 8 |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Other investments | 0 | 0 |
Fair value assets, total | 906 | 933 |
Liabilities: | ||
Liability Derivatives | 250 | |
Interest rate derivatives | 24 | |
Fair value liabilities, total | 225 | |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 69 | 85 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 160 | 184 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 152 | 130 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 64 | 62 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 278 | 299 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 145 | 139 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 9 | 13 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 7 | 13 |
Liabilities: | ||
Liability Derivatives | 220 | 201 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 30 | |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Assets: | ||
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Other investments | 1 | 1 |
Fair value assets, total | 1 | 1 |
Liabilities: | ||
Liability Derivatives | 0 | |
Interest rate derivatives | 0 | |
Fair value liabilities, total | 0 | |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | ||
Nuclear decommissioning trusts: | ||
Fair value assets, total | 17 | 3 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 17 | 3 |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 18 | 18 |
Fair value assets, total | 19 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 1 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 100 | 72 |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 18 | 18 |
Fair value assets, total | 18 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 1 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 1 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 100 | 72 |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 0 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | |
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 63 | 802 |
Fair value assets, total | 845 | |
Liabilities: | ||
Liability Derivatives | 21 | 41 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 183 | 182 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 113 | 121 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 125 | 96 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 64 | 62 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 143 | 188 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 127 | 121 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 20 | 19 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 5 | 6 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 2 | 7 |
Liabilities: | ||
Liability Derivatives | 15 | 27 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 6 | 14 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 63 | 191 |
Fair value assets, total | 261 | |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 182 | 180 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 16 | 11 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 611 |
Fair value assets, total | 584 | |
Liabilities: | ||
Liability Derivatives | 21 | 41 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 1 | 2 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 113 | 121 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 125 | 96 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 64 | 62 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 143 | 188 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 127 | 121 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 4 | 8 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 5 | 6 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 2 | 7 |
Liabilities: | ||
Liability Derivatives | 15 | 27 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 6 | 14 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 0 | |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Alabama Power [Member] | ||
Assets: | ||
Asset Derivatives | 1 | 1 |
Liabilities: | ||
Liability Derivatives | 70 | 61 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 68 | 162 |
Fair value assets, total | 803 | 917 |
Liabilities: | ||
Liability Derivatives | 70 | 61 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 427 | 486 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 94 | 97 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 27 | 34 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 146 | 111 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 18 | 18 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 17 | 3 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 5 | 5 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 1 | 1 |
Liabilities: | ||
Liability Derivatives | 55 | 53 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 15 | 8 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 68 | 162 |
Fair value assets, total | 485 | 599 |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 359 | 403 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 47 | 34 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 11 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 301 | 315 |
Liabilities: | ||
Liability Derivatives | 70 | 61 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 68 | 83 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 47 | 63 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 27 | 34 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 135 | 111 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 18 | 18 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 5 | 5 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 1 | 1 |
Liabilities: | ||
Liability Derivatives | 55 | 53 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 15 | 8 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | ||
Nuclear decommissioning trusts: | ||
Fair value assets, total | 17 | 3 |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Private equity [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 17 | 3 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 52 | 115 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 47 | 45 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 52 | 115 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 47 | 45 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||
Liabilities: | ||
Liability Derivatives | 0 | 0 |
Southern Power [Member] | ||
Assets: | ||
Asset Derivatives | 7 | 5 |
Liabilities: | ||
Liability Derivatives | 3 | 4 |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Assets: | ||
Asset Derivatives | 4 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 511 | 18 |
Fair value assets, total | 518 | 23 |
Liabilities: | ||
Liability Derivatives | 3 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 3 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 5 | |
Liabilities: | ||
Liability Derivatives | 4 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Assets: | ||
Asset Derivatives | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 511 | 18 |
Fair value assets, total | 511 | 18 |
Liabilities: | ||
Liability Derivatives | 0 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 0 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | |
Liabilities: | ||
Liability Derivatives | 0 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Asset Derivatives | 4 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 7 | 5 |
Liabilities: | ||
Liability Derivatives | 3 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | 3 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 5 | |
Liabilities: | ||
Liability Derivatives | 4 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Assets: | ||
Asset Derivatives | 0 | |
Nuclear decommissioning trusts: | ||
Cash equivalents | 0 | 0 |
Fair value assets, total | 0 | 0 |
Liabilities: | ||
Liability Derivatives | 0 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||
Nuclear decommissioning trusts: | ||
Nuclear decommissioning trusts | $ 0 | |
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||
Assets: | ||
Asset Derivatives | 0 | |
Liabilities: | ||
Liability Derivatives | $ 0 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value, Nature and Risk of Investments (Details) - Private equity [Member] - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | $ 17,000,000 | $ 3,000,000 |
Unfunded Commitments | 28,000,000 | 7,000,000 |
Alabama Power [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 17,000,000 | 3,000,000 |
Unfunded Commitments | $ 28,000,000 | $ 7,000,000 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments, Carrying Amount Not Equal to Fair Value (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Long-term debt: | ||
Long-term debt, Carrying Amount | $ 27,216 | $ 23,814 |
Long-term debt, Fair Value | 27,913 | 25,816 |
Alabama Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 6,849 | 6,586 |
Long-term debt, Fair Value | 7,192 | 7,321 |
Georgia Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 10,145 | 9,673 |
Long-term debt, Fair Value | 10,480 | 10,552 |
Gulf Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 1,303 | 1,362 |
Long-term debt, Fair Value | 1,339 | 1,477 |
Mississippi Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 2,537 | 2,320 |
Long-term debt, Fair Value | 2,413 | 2,382 |
Southern Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 3,122 | 1,610 |
Long-term debt, Fair Value | $ 3,117 | $ 1,785 |
Fair Value Measurements - Textu
Fair Value Measurements - Textual (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Private equity [Member] | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period | 10 years |
Derivatives - Energy-Related, I
Derivatives - Energy-Related, Interest Rate, and Foreign Currency Derivatives Information (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015USD ($)MMBTU | Dec. 31, 2014USD ($) | |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 29,000 | $ 21,000 |
Derivative Liability, Fair Value, Gross Liability | 250,000 | 225,000 |
Interest rate derivative contracts | ||
Notional Amount | 4,407,000 | |
Fair Value Gain (Loss) | (8,000) | |
Alabama Power [Member] | ||
Derivative [Line Items] | ||
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | 4,000 | |
Derivative Asset, Fair Value, Gross Asset | 1,000 | 1,000 |
Derivative Liability, Fair Value, Gross Liability | $ 70,000 | 61,000 |
Energy-related derivative contracts | ||
Net Purchased mmBtu | MMBTU | 50,000,000 | |
Longest Hedge Date | 2,018 | |
Gulf Power [Member] | ||
Energy-related derivative contracts | ||
Net Purchased mmBtu | MMBTU | 82,000,000 | |
Longest Hedge Date | 2,020 | |
Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 7,000 | 5,000 |
Derivative Liability, Fair Value, Gross Liability | 3,000 | 4,000 |
Interest rate derivative contracts | ||
Notional Amount | 177,000 | |
Fair Value Gain (Loss) | 3,000 | |
Georgia Power [Member] | ||
Derivative [Line Items] | ||
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | 4,000 | |
Interest rate derivative contracts | ||
Notional Amount | 1,400,000 | |
Fair Value Gain (Loss) | 0 | |
Mississippi Power [Member] | ||
Derivative [Line Items] | ||
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | $ 1,000 | |
Energy-related derivative contracts | ||
Net Purchased mmBtu | MMBTU | 32,000,000 | |
Longest Hedge Date | 2,018 | |
Maturity Date March 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 250,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.32% | |
Interest rate | 0.75% | |
Derivative, basis spread on variable interest rate | 0.32% | |
Derivative, Maturity Date | Mar. 15, 2016 | |
Fair Value Gain (Loss) | $ 0 | |
Maturity Date March 2016 [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 250,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.32% | |
Interest rate | 0.75% | |
Derivative, Maturity Date | Mar. 1, 2016 | |
Fair Value Gain (Loss) | $ 0 | |
Maturity Date March 2016 [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Derivative, basis spread on variable interest rate | 0.32% | |
Maturity Date August 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 200,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.40% | |
Interest rate | 1.01% | |
Derivative, basis spread on variable interest rate | 0.40% | |
Derivative, Maturity Date | Aug. 15, 2016 | |
Fair Value Gain (Loss) | $ 0 | |
Maturity Date August 2016 [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 200,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.40% | |
Interest rate | 1.01% | |
Derivative, Maturity Date | Aug. 1, 2016 | |
Fair Value Gain (Loss) | $ 0 | |
Maturity Date August 2016 [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Derivative, basis spread on variable interest rate | 0.40% | |
Maturity Date November 2026 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 1,000,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.37% | |
Derivative, Maturity Date | Nov. 30, 2026 | |
Fair Value Gain (Loss) | $ 1,000 | |
Maturity Date November 2046 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 1,000,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.70% | |
Derivative, Maturity Date | Nov. 30, 2046 | |
Fair Value Gain (Loss) | $ (1,000) | |
Maturity Date October 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 200,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.93% | |
Derivative, Maturity Date | Oct. 15, 2025 | |
Fair Value Gain (Loss) | $ (15,000) | |
Maturity Date October 2025 [Member] | Alabama Power [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 200,000 | |
Derivative Interest Rate Received | 3-month  LIBOR | |
Interest rate | 2.93% | |
Derivative, Maturity Date | Oct. 1, 2025 | |
Fair Value Gain (Loss) | $ (15,000) | |
Maturity Date November 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 80,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.32% | |
Derivative, Maturity Date | Dec. 15, 2026 | |
Fair Value Gain (Loss) | $ 1,000 | |
Maturity Date October 2025 [Member] | Gulf Power [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 80,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.32% | |
Derivative, Maturity Date | Dec. 1, 2026 | |
Fair Value Gain (Loss) | $ 1,000 | |
Maturity Date June 2018 [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 250,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 4.02% | |
Interest rate | 5.40% | |
Derivative, basis spread on variable interest rate | 4.02% | |
Derivative, Maturity Date | Jun. 1, 2018 | |
Fair Value Gain (Loss) | $ 1,000 | |
Maturity Date June 2018 [Member] | Georgia Power [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 250,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 4.02% | |
Interest rate | 5.40% | |
Derivative, basis spread on variable interest rate | 4.02% | |
Derivative, Maturity Date | Jun. 1, 2018 | |
Fair Value Gain (Loss) | $ 1,000 | |
Maturity Date December 2019 [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 200,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 2.46% | |
Interest rate | 4.25% | |
Derivative, basis spread on variable interest rate | 2.46% | |
Derivative, Maturity Date | Dec. 1, 2019 | |
Fair Value Gain (Loss) | $ 2,000 | |
Maturity Date December 2019 [Member] | Georgia Power [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 200,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 2.46% | |
Interest rate | 4.25% | |
Derivative, basis spread on variable interest rate | 2.46% | |
Derivative, Maturity Date | Dec. 1, 2019 | |
Fair Value Gain (Loss) | $ 2,000 | |
Maturity Date August 2017 [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 250,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.17% | |
Interest rate | 1.30% | |
Derivative, basis spread on variable interest rate | 0.17% | |
Derivative, Maturity Date | Aug. 15, 2017 | |
Fair Value Gain (Loss) | $ 1,000 | |
Maturity Date June 2020 [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 300,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.92% | |
Interest rate | 2.75% | |
Derivative, basis spread on variable interest rate | 0.92% | |
Derivative, Maturity Date | Jun. 15, 2020 | |
Fair Value Gain (Loss) | $ 2,000 | |
Maturity Date December 2018 [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 500,000 | |
Derivative Interest Rate Received | 3-month LIBOR + 0.76% | |
Interest rate | 1.95% | |
Derivative, basis spread on variable interest rate | 0.76% | |
Derivative, Maturity Date | Dec. 1, 2018 | |
Fair Value Gain (Loss) | $ (3,000) | |
Maturity Date December 2018 [Member] | Georgia Power [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 500,000 | |
Derivative Interest Rate Received | 3-month LIBOR + .76% | |
Interest rate | 1.95% | |
Derivative, basis spread on variable interest rate | 0.76% | |
Derivative, Maturity Date | Dec. 1, 2018 | |
Fair Value Gain (Loss) | $ (3,000) | |
Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 4,000 | 6,000 |
Derivative Liability, Fair Value, Gross Liability | 1,000 | 4,000 |
Not Designated as Hedging Instrument [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1,000 | 0 |
Derivative Liability, Fair Value, Gross Liability | 100,000 | 72,000 |
Not Designated as Hedging Instrument [Member] | Southern Power [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 4,000 | 5,000 |
Derivative Liability, Fair Value, Gross Liability | $ 1,000 | 4,000 |
Not Designated as Hedging Instrument [Member] | Maturity Date October 2016 [Member] | Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative, Term of Contract | 15 years | |
Not Designated as Hedging Instrument [Member] | Maturity Date November 2016 [Member] | Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative, Term of Contract | 12 years | |
Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 1,000 | 6,000 |
Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 3,000 | 0 |
Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 1,000 | 4,000 |
Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member] | Southern Power [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | $ 0 |
RE Tranquility Holdings, LLC [Member] | Not Designated as Hedging Instrument [Member] | Maturity Date October 2016 [Member] | Southern Power [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 65,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.50% | |
Derivative, Maturity Date | Oct. 31, 2016 | |
Fair Value Gain (Loss) | $ 1,000 | |
RE Roserock Holdings, LLC [Member] | Not Designated as Hedging Instrument [Member] | Maturity Date October 2016 [Member] | Southern Power [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 47,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.21% | |
Fair Value Gain (Loss) | $ 1,000 | |
RE Garland Holdings, LLC [Member] | Maturity Date November 2016 [Member] | Southern Power [Member] | Fair Value Hedges Of Existing Debt [Member] | ||
Interest rate derivative contracts | ||
Derivative, Maturity Date | Nov. 22, 2016 | |
RE Garland Holdings, LLC [Member] | Not Designated as Hedging Instrument [Member] | Maturity Date November 2016 [Member] | Southern Power [Member] | ||
Interest rate derivative contracts | ||
Notional Amount | $ 65,000 | |
Derivative Interest Rate Received | 3-month LIBOR | |
Interest rate | 2.21% | |
Fair Value Gain (Loss) | $ 1,000 |
Derivatives - Financial Stateme
Derivatives - Financial Statement Presentation (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | $ 217,000 | $ 197,000 |
Regulatory Hedge Unrealized Gain | 3,000 | 7,000 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 29,000 | 21,000 |
Liability Derivatives | 250,000 | 225,000 |
Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 4,000 | 6,000 |
Liability Derivatives | 1,000 | 4,000 |
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000 | 13,000 |
Liability Derivatives | 220,000 | 201,000 |
Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 130,000 | 118,000 |
Energy Related Derivative [Member] | Other current assets [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 6,000 |
Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 1,000 | 4,000 |
Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 3,000 | 7,000 |
Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 87,000 | 79,000 |
Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 0 |
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (6,000) | (9,000) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (6,000) | (9,000) |
Interest rate derivatives [Member] | Net Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 22,000 | 8,000 |
Liability Derivatives | 30,000 | 24,000 |
Interest rate derivatives [Member] | Other current assets [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 3,000 | 0 |
Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 0 | 0 |
Interest rate derivatives [Member] | Gross Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (9,000) | (8,000) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (9,000) | (8,000) |
Georgia Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 2,000 | 7,000 |
Liability Derivatives | 15,000 | 27,000 |
Georgia Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (2,000) | (7,000) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (2,000) | (7,000) |
Georgia Power [Member] | Interest rate derivatives [Member] | Net Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 5,000 | 6,000 |
Liability Derivatives | 6,000 | 14,000 |
Georgia Power [Member] | Interest rate derivatives [Member] | Gross Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (4,000) | (6,000) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (4,000) | (6,000) |
Alabama Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 1,000 |
Liability Derivatives | 70,000 | 61,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 1,000 |
Liability Derivatives | 55,000 | 53,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 40,000 | 32,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 1,000 | 1,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 15,000 | 21,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 0 |
Alabama Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (1,000) | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (1,000) | 0 |
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 0 |
Liability Derivatives | 100,000 | 72,000 |
Southern Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000 | 5,000 |
Liability Derivatives | 3,000 | 4,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 4,000 | 5,000 |
Liability Derivatives | 1,000 | 4,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 4,000 | 5,000 |
Liability Derivatives | 3,000 | 4,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Assets from risk management activities [Member] | Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 3,000 | 0 |
Southern Power [Member] | Energy Related Derivative [Member] | Assets from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 5,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 2,000 | 0 |
Southern Power [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 1,000 | 4,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (1,000) | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (1,000) | 0 |
Southern Power [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 0 | 0 |
Southern Power [Member] | Interest rate derivatives [Member] | Assets from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 3,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 3,000 | 7,000 |
Liability Derivatives | 217,000 | 197,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 3,000 | 7,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 130,000 | 118,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 87,000 | 79,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 47,000 | 45,000 |
Regulatory Hedge Unrealized Gain | 0 | 0 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Liability Derivatives | 47,000 | 45,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 29,000 | 26,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 29,000 | 26,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 18,000 | 19,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 18,000 | 19,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000 | 13,000 |
Liability Derivatives | 21,000 | 41,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 2,000 | 7,000 |
Liability Derivatives | 15,000 | 27,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 12,000 | 23,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 2,000 | 6,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 12,000 | 23,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 1,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 1,000 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 3,000 | 4,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 2,000 | 6,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 3,000 | 4,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 5,000 | 6,000 |
Liability Derivatives | 6,000 | 14,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 5,000 | 5,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 0 | 9,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 1,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 6,000 | 5,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 1,000 |
Liability Derivatives | 55,000 | 53,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 1,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 40,000 | 32,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 15,000 | 21,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 15,000 | 8,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 100,000 | 72,000 |
Regulatory Hedge Unrealized Gain | 0 | 0 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Liability Derivatives | 100,000 | 72,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 49,000 | 37,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 49,000 | 37,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 51,000 | 35,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 51,000 | 35,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 0 | 0 |
Cash Flow and Fair Value Hedging [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 22,000 | 8,000 |
Liability Derivatives | 32,000 | 24,000 |
Cash Flow and Fair Value Hedging [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 3,000 | 0 |
Cash Flow and Fair Value Hedging [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 2,000 | 0 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 19,000 | 7,000 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 23,000 | 17,000 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 1,000 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | $ 7,000 | $ 7,000 |
Derivatives - Balance Sheet Off
Derivatives - Balance Sheet Offsetting (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 29 | $ 21 |
Derivative Liability, Fair Value, Gross Liability | 250 | 225 |
Alabama Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 1 |
Derivative Liability, Fair Value, Gross Liability | 70 | 61 |
Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 7 | 5 |
Derivative Liability, Fair Value, Gross Liability | 3 | 4 |
Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1 | 4 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 214 | 192 |
Energy Related Derivative [Member] | Alabama Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 1 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 54 | 53 |
Energy Related Derivative [Member] | Georgia Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 13 | 20 |
Energy Related Derivative [Member] | Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 3 | 5 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 2 | 4 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 13 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 21 | 16 |
Interest Rate Contract [Member] | Georgia Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1 | 0 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 2 | 8 |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 7 | 13 |
Derivative Liability, Fair Value, Gross Liability | 220 | 201 |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Alabama Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 1 |
Derivative Liability, Fair Value, Gross Liability | 55 | 53 |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Georgia Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 7 |
Derivative Liability, Fair Value, Gross Liability | 15 | 27 |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 4 | 5 |
Derivative Liability, Fair Value, Gross Liability | 3 | 4 |
Net Amount Of Derivatives [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 22 | 8 |
Derivative Liability, Fair Value, Gross Liability | 30 | 24 |
Net Amount Of Derivatives [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 6 |
Derivative Liability, Fair Value, Gross Liability | 6 | 14 |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (6) | (9) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (6) | (9) |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Alabama Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (1) | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (1) | 0 |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Georgia Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (2) | (7) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (2) | (7) |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Southern Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (1) | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (1) | 0 |
Gross Amount Of Derivatives [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (9) | (8) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (9) | (8) |
Gross Amount Of Derivatives [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (4) | (6) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ (4) | $ (6) |
Derivatives - Pre-tax Effect of
Derivatives - Pre-tax Effect of Derivatives on Balance Sheets and Statements of Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | $ (217) | $ (197) | |
Regulatory Hedge Unrealized Gain | 3 | 7 | |
Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | (22) | (16) | $ 0 |
Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | (9) | (8) | (14) |
Other regulatory assets current [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (130) | (118) | |
Other regulatory assets deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (87) | (79) | |
Other regulatory liabilities current [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 3 | 7 | |
Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Alabama Power [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | (3) | (3) | (3) |
Alabama Power [Member] | Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | (7) | (8) | 0 |
Alabama Power [Member] | Other regulatory assets current [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (40) | (32) | |
Alabama Power [Member] | Other regulatory assets deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (15) | (21) | |
Alabama Power [Member] | Other regulatory assets [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (55) | (53) | |
Alabama Power [Member] | Other Current Liabilities [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 1 | 1 | |
Alabama Power [Member] | Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Alabama Power [Member] | Other regulatory liabilities [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 1 | 1 | |
Gulf Power [Member] | Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | 1 | 0 | 0 |
Gulf Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | (1) | (1) | (1) |
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (100) | (72) | |
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Gulf Power [Member] | Other regulatory assets current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (49) | (37) | |
Gulf Power [Member] | Other regulatory assets deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (51) | (35) | |
Gulf Power [Member] | Other regulatory liabilities current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Gulf Power [Member] | Other regulatory liabilities deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (47) | (45) | |
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Mississippi Power [Member] | Other regulatory assets current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (29) | (26) | |
Mississippi Power [Member] | Other regulatory assets deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (18) | (19) | |
Mississippi Power [Member] | Other regulatory liabilities current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Mississippi Power [Member] | Other regulatory liabilities deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 0 | |
Southern Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | (1) | (1) | (6) |
Georgia Power [Member] | Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | (15) | (8) | 0 |
Georgia Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | (3) | (3) | $ (3) |
Georgia Power [Member] | Other regulatory assets current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (12) | (23) | |
Georgia Power [Member] | Other regulatory assets deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (3) | (4) | |
Georgia Power [Member] | Other regulatory assets [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | (15) | (27) | |
Georgia Power [Member] | Other regulatory liabilities current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 2 | 6 | |
Georgia Power [Member] | Other deferred credits and liabilities [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 1 | |
Georgia Power [Member] | Other regulatory liabilities [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | $ 2 | $ 7 |
Derivatives - Textual (Details)
Derivatives - Textual (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($)MMBTU | |
Derivative [Line Items] | |
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 5,000,000 |
Fair value of derivative liabilities with contingent features | $ 52 |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | $ 52 |
Georgia Power [Member] | |
Derivative [Line Items] | |
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 4,000,000 |
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | $ 4 |
Fair value of derivative liabilities with contingent features | 1 |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | $ 52 |
Alabama Power [Member] | |
Derivative [Line Items] | |
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 50,000,000 |
Longest Hedge Date | 2,018 |
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | $ 4 |
Fair value of derivative liabilities with contingent features | 16 |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | $ 52 |
Gulf Power [Member] | |
Derivative [Line Items] | |
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 82,000,000 |
Longest Hedge Date | 2,020 |
Fair value of derivative liabilities with contingent features | $ 22 |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | $ 52 |
Mississippi Power [Member] | |
Derivative [Line Items] | |
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 32,000,000 |
Longest Hedge Date | 2,018 |
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | $ 1 |
Fair value of derivative liabilities with contingent features | 12 |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | $ 52 |
Southern Power [Member] | |
Derivative [Line Items] | |
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU | 1,000,000 |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | $ 52 |
Public Utilities, Inventory, Natural Gas [Member] | |
Derivative [Line Items] | |
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 224,000,000 |
Public Utilities, Inventory, Natural Gas [Member] | Georgia Power [Member] | |
Derivative [Line Items] | |
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 50,000,000 |
Longest Hedge Date | 2,017 |
Public Utilities, Inventory, Natural Gas [Member] | Southern Power [Member] | |
Derivative [Line Items] | |
Net volume of energy-related derivative contracts for natural gas positions | MMBTU | 10,000,000 |
Longest Non-Hedge Date | 2,017 |
Public Utilities, Inventory, Fuel [Member] | |
Derivative [Line Items] | |
Longest Hedge Date | 2,020 |
Longest Non-Hedge Date | 2,017 |
Segment and Related Informati98
Segment and Related Information - Financial Data for Business Segments and Products and Services (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015USD ($)entities | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)entities | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Segment Reporting Information [Line Items] | |||||||||||
Number of traditional operating companies | entities | 4 | 4 | |||||||||
Revenues | $ 3,568 | $ 5,401 | $ 4,337 | $ 4,183 | $ 4,017 | $ 5,339 | $ 4,467 | $ 4,644 | $ 17,489 | $ 18,467 | $ 17,087 |
Financial data for business segments | |||||||||||
Operating revenues | 3,568 | 5,401 | 4,337 | 4,183 | 4,017 | 5,339 | 4,467 | 4,644 | 17,489 | 18,467 | 17,087 |
Depreciation and amortization | 2,034 | 1,945 | 1,901 | ||||||||
Interest income | 23 | 19 | 19 | ||||||||
Interest expense | 840 | 835 | 824 | ||||||||
Income taxes | 1,194 | 977 | 849 | ||||||||
Segment net income (loss) | 271 | 959 | 629 | 508 | 283 | 718 | $ 611 | 351 | 2,367 | 1,963 | 1,644 |
Total assets | 78,318 | 70,233 | 78,318 | 70,233 | 64,264 | ||||||
Gross property additions | 6,169 | 6,522 | 5,868 | ||||||||
Segment and Related Information (Textual) [Abstract] | |||||||||||
Unamortized Debt Issuance Expense | 241 | 202 | 241 | 202 | 139 | ||||||
Kemper IGCC [Member] | |||||||||||
Segment and Related Information (Textual) [Abstract] | |||||||||||
Pre-Tax Charge To Income | 183 | 150 | 23 | 9 | 70 | 418 | 380 | 365 | 868 | 1,200 | |
After Tax Charge To Income | 113 | $ 93 | $ 14 | $ 6 | 43 | $ 258 | $ 235 | 226 | 536 | 729 | |
Electric Utilities [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 17,442 | 18,406 | 17,035 | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | 17,442 | 18,406 | 17,035 | ||||||||
Depreciation and amortization | 2,020 | 1,929 | 1,886 | ||||||||
Interest income | 22 | 18 | 18 | ||||||||
Interest expense | 774 | 794 | 788 | ||||||||
Income taxes | 1,326 | 1,053 | 935 | ||||||||
Segment net income (loss) | 2,401 | 1,969 | 1,652 | ||||||||
Total assets | 77,560 | 69,402 | 77,560 | 69,402 | 63,504 | ||||||
Gross property additions | 6,129 | 6,510 | 5,859 | ||||||||
Traditional Operating Companies [Member] | Electric Utilities [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 16,491 | 17,354 | 16,136 | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | 16,491 | 17,354 | 16,136 | ||||||||
Depreciation and amortization | 1,772 | 1,709 | 1,711 | ||||||||
Interest income | 19 | 17 | 17 | ||||||||
Interest expense | 697 | 705 | 714 | ||||||||
Income taxes | 1,305 | 1,056 | 889 | ||||||||
Segment net income (loss) | 2,186 | 1,797 | 1,486 | ||||||||
Total assets | 69,052 | 64,300 | 69,052 | 64,300 | 59,188 | ||||||
Gross property additions | 5,124 | 5,568 | 5,226 | ||||||||
Southern Power [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 417 | 383 | 346 | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | 417 | 383 | 346 | ||||||||
Southern Power [Member] | Electric Utilities [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 1,390 | 1,501 | 1,275 | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | 1,390 | 1,501 | 1,275 | ||||||||
Depreciation and amortization | 248 | 220 | 175 | ||||||||
Interest income | 2 | 1 | 1 | ||||||||
Interest expense | 77 | 89 | 74 | ||||||||
Income taxes | 21 | (3) | 46 | ||||||||
Segment net income (loss) | 215 | 172 | 166 | ||||||||
Total assets | 8,905 | 5,233 | 8,905 | 5,233 | 4,417 | ||||||
Gross property additions | 1,005 | 942 | 633 | ||||||||
All Other [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 152 | 159 | 139 | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | 152 | 159 | 139 | ||||||||
Depreciation and amortization | 14 | 16 | 15 | ||||||||
Interest income | 6 | 3 | 2 | ||||||||
Interest expense | 69 | 43 | 36 | ||||||||
Income taxes | (132) | (76) | (85) | ||||||||
Segment net income (loss) | (32) | (3) | (10) | ||||||||
Total assets | 1,819 | 1,143 | 1,819 | 1,143 | 1,064 | ||||||
Gross property additions | 40 | 11 | 9 | ||||||||
Intersegment Eliminations [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | (105) | (98) | (87) | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | (105) | (98) | (87) | ||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||
Interest income | (5) | (2) | (1) | ||||||||
Interest expense | (3) | (2) | 0 | ||||||||
Income taxes | 0 | 0 | (1) | ||||||||
Segment net income (loss) | (2) | (3) | 2 | ||||||||
Total assets | (1,061) | (312) | (1,061) | (312) | (304) | ||||||
Gross property additions | 0 | 1 | 0 | ||||||||
Intersegment Eliminations [Member] | Electric Utilities [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | (439) | (449) | (376) | ||||||||
Financial data for business segments | |||||||||||
Operating revenues | (439) | (449) | (376) | ||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||
Interest income | 1 | 0 | 0 | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Income taxes | 0 | 0 | 0 | ||||||||
Segment net income (loss) | 0 | 0 | 0 | ||||||||
Total assets | $ (397) | $ (131) | (397) | (131) | (101) | ||||||
Gross property additions | $ 0 | 0 | 0 | ||||||||
Deferred Tax Liability, Noncurrent [Member] | |||||||||||
Segment and Related Information (Textual) [Abstract] | |||||||||||
Prior Period Reclassification Adjustment | $ 488 | $ 143 |
Segment and Related Informati99
Segment and Related Information - Electric Utilities' Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | $ 3,568 | $ 5,401 | $ 4,337 | $ 4,183 | $ 4,017 | $ 5,339 | $ 4,467 | $ 4,644 | $ 17,489 | $ 18,467 | $ 17,087 |
Retail [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | 14,987 | 15,550 | 14,541 | ||||||||
Wholesale [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | 1,798 | 2,184 | 1,855 | ||||||||
Other Electric Revenue [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | 657 | 672 | 639 | ||||||||
Electric Utilities [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | $ 17,442 | $ 18,406 | $ 17,035 |
Noncontrolling Interest (Detail
Noncontrolling Interest (Details) - Southern Power [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Noncontrolling Interest [Roll Forward] | |||
Redeemable Put Option, Beginning balance | $ 39 | $ 29 | $ 8 |
Net income attributable to redeemable noncontrolling interest | 2 | 4 | 4 |
Distributions to redeemable noncontrolling interest | 0 | (1) | 0 |
Capital contributions from redeemable noncontrolling interest | 2 | 7 | 17 |
Redeemable Put Option, Ending balance | $ 43 | $ 39 | $ 29 |
Noncontrolling Interest - Net I
Noncontrolling Interest - Net Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | $ (12) | $ 2 | |
Net Income (Loss) | 2,435 | 2,031 | $ 1,710 |
Noncontrolling Interest [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | (12) | 2 | |
Southern Power [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net income attributable to Southern Power Company | 215 | 172 | 166 |
Net Income (Loss) Attributable to Noncontrolling Interest | 12 | (2) | |
Net income attributable to redeemable noncontrolling interest | 2 | 4 | 4 |
Net Income (Loss) | 229 | 175 | $ 166 |
Southern Power [Member] | Noncontrolling Interest [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | $ 12 | (2) | |
Southern Power [Member] | Noncontrolling Interests [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | $ (1) |
Noncontrolling Interest - Textu
Noncontrolling Interest - Textuals (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Southern Power [Member] | |||
Redeemable Noncontrolling Interest [Line Items] | |||
Net income attributable to redeemable noncontrolling interest | $ 2 | $ 4 | $ 4 |
Quarterly Financial Informat103
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Summarized quarterly financial information | |||||||||||
Operating revenues | $ 3,568 | $ 5,401 | $ 4,337 | $ 4,183 | $ 4,017 | $ 5,339 | $ 4,467 | $ 4,644 | $ 17,489 | $ 18,467 | $ 17,087 |
Operating Income (Loss) | 578 | 1,649 | 1,098 | 957 | 561 | 1,278 | 1,103 | 700 | 4,282 | 3,642 | 3,255 |
Net Income (Loss) After Dividends on Preferred and Preference Stock | $ 271 | $ 959 | $ 629 | $ 508 | $ 283 | $ 718 | $ 611 | $ 351 | $ 2,367 | $ 1,963 | $ 1,644 |
Basic Earnings, Per Common Share (in dollars per share) | $ 0.30 | $ 1.05 | $ 0.69 | $ 0.56 | $ 0.31 | $ 0.80 | $ 0.68 | $ 0.39 | $ 2.60 | $ 2.19 | $ 1.88 |
Diluted Earnings, Per Common Share (in dollars per share) | 0.30 | 1.05 | 0.69 | 0.56 | 0.31 | 0.80 | 0.68 | 0.39 | 2.59 | 2.18 | 1.87 |
Cash dividends (in dollars per share) | 0.5425 | 0.5425 | 0.5425 | 0.525 | 0.525 | 0.525 | 0.525 | 0.5075 | $ 2.1525 | $ 2.0825 | $ 2.0125 |
Trading Price Range, High, Per Common Share (in dollars per share) | 47.5 | 46.84 | 45.44 | 53.16 | 51.28 | 45.47 | 46.81 | 44 | |||
Trading Price Range, Low, Per Common Share (in dollars per share) | $ 43.38 | $ 41.81 | $ 41.4 | $ 43.55 | $ 43.55 | $ 41.87 | $ 42.55 | $ 40.27 | |||
Alabama Power [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Operating revenues | $ 1,217 | $ 1,695 | $ 1,455 | $ 1,401 | $ 1,328 | $ 1,669 | $ 1,437 | $ 1,508 | $ 5,768 | $ 5,942 | $ 5,618 |
Operating Income (Loss) | 264 | 555 | 398 | 346 | 267 | 520 | 357 | 381 | 1,563 | 1,525 | 1,476 |
Net Income (Loss) After Dividends on Preferred and Preference Stock | 121 | 295 | 200 | 169 | 119 | 282 | 173 | 187 | 785 | 761 | 712 |
Georgia Power [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Operating revenues | 1,641 | 2,691 | 2,016 | 1,978 | 1,902 | 2,631 | 2,186 | 2,269 | 8,326 | 8,988 | 8,274 |
Operating Income (Loss) | 376 | 964 | 554 | 454 | 288 | 920 | 572 | 516 | 2,348 | 2,296 | 2,240 |
Net Income (Loss) After Dividends on Preferred and Preference Stock | 196 | 551 | 277 | 236 | 123 | 525 | 311 | 266 | 1,260 | 1,225 | 1,174 |
Gulf Power [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Operating revenues | 313 | 429 | 384 | 357 | 361 | 438 | 384 | 407 | 1,483 | 1,590 | 1,440 |
Operating Income (Loss) | 58 | 91 | 69 | 72 | 50 | 88 | 69 | 74 | 290 | 281 | 265 |
Net Income (Loss) After Dividends on Preferred and Preference Stock | 28 | 48 | 35 | 37 | 23 | 46 | 34 | 37 | 148 | 140 | 124 |
Mississippi Power [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Operating revenues | 246 | 341 | 275 | 276 | 246 | 355 | 311 | 331 | 1,138 | 1,243 | 1,145 |
Operating Income (Loss) | (143) | (66) | 12 | 24 | (71) | (349) | 56 | (325) | (173) | (689) | (922) |
Net Income (Loss) After Dividends on Preferred and Preference Stock | (71) | (21) | 49 | 35 | (24) | (195) | 62 | (172) | (8) | (329) | (477) |
Southern Power [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Operating revenues | 304 | 401 | 337 | 348 | 386 | 435 | 329 | 351 | 1,390 | 1,501 | 1,275 |
Operating Income (Loss) | 55 | 129 | 75 | 67 | 40 | 105 | 51 | 59 | 326 | 255 | 290 |
Net Income (Loss) After Dividends on Preferred and Preference Stock | 34 | 102 | 46 | 33 | 44 | 64 | $ 31 | 33 | |||
Kemper IGCC [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Pre-Tax Charge To Income | 183 | 150 | 23 | 9 | 70 | 418 | 380 | 365 | 868 | 1,200 | |
After Tax Charge To Income | 113 | 93 | 14 | 6 | 43 | 258 | 235 | 226 | 536 | 729 | |
Kemper IGCC [Member] | Mississippi Power [Member] | |||||||||||
Summarized quarterly financial information | |||||||||||
Pre-Tax Charge To Income | 183 | 150 | 23 | 9 | 70 | 418 | 380 | 365 | 868 | 1,100 | |
After Tax Charge To Income | $ 113 | $ 93 | $ 14 | $ 6 | $ 43 | $ 258 | $ 235 | $ 226 | $ 536 | $ 681 |
Valuation and Qualifying Acc104
Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | 36 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | |
Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of period | $ 18,253 | $ 17,855 | $ 16,984 | $ 16,984 |
Additions Charged to Income | 31,074 | 43,537 | 36,788 | |
Additions Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | 35,986 | 43,139 | 35,917 | |
Balance at End of Period | 13,341 | 18,253 | 17,855 | 13,341 |
Alabama Power [Member] | Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of period | 9,143 | 8,350 | 8,450 | 8,450 |
Additions Charged to Income | 13,500 | 14,309 | 12,327 | |
Additions Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | 13,046 | 13,516 | 12,427 | |
Balance at End of Period | 9,597 | 9,143 | 8,350 | 9,597 |
Georgia Power [Member] | Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of period | 6,076 | 5,074 | 6,259 | 6,259 |
Additions Charged to Income | 16,862 | 24,141 | 18,362 | |
Additions Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | 20,791 | 23,139 | 19,547 | |
Balance at End of Period | 2,147 | 6,076 | 5,074 | 2,147 |
Gulf Power [Member] | Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of period | 2,087 | 1,131 | 1,490 | 1,490 |
Additions Charged to Income | 2,041 | 4,304 | 1,900 | |
Additions Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | 3,353 | 3,348 | 2,259 | |
Balance at End of Period | 775 | 2,087 | 1,131 | 775 |
Mississippi Power [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Retail Rate Recovery | 371,000 | 342,000 | ||
Mississippi Power [Member] | Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of period | 825 | 3,018 | 373 | 373 |
Additions Charged to Income | (1,994) | 562 | 3,757 | |
Additions Charged to Other Accounts | 0 | 0 | 0 | |
Deductions | (1,456) | 2,755 | 1,112 | |
Balance at End of Period | $ 287 | $ 825 | $ 3,018 | $ 287 |