Georgia Power (GPJA) 10-K 22 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
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, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
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			$ 51.1
Entity Common Stock, Shares Outstanding		991,051,161
Alabama Power [Member]
Document Information [Line Items]
Entity Registrant Name	ALABAMA POWER CO
Entity Central Index Key	3,153
Entity Well-known Seasoned Issuer	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		30,537,500
Georgia Power [Member]
Document Information [Line Items]
Entity Registrant Name	GEORGIA POWER CO
Entity Central Index Key	41,091
Entity Well-known Seasoned Issuer	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		9,261,500
Gulf Power [Member]
Document Information [Line Items]
Entity Registrant Name	GULF POWER CO
Entity Central Index Key	44,545
Entity Well-known Seasoned Issuer	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		7,392,717
Mississippi Power [Member]
Document Information [Line Items]
Entity Registrant Name	MISSISSIPPI POWER CO
Entity Central Index Key	66,904
Entity Well-known Seasoned Issuer	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,121,000
Southern Power [Member]
Document Information [Line Items]
Entity Registrant Name	SOUTHERN POWER CO
Entity Central Index Key	1,160,661
Entity Well-known Seasoned Issuer	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000
Southern Company Gas [Member]
Document Information [Line Items]
Entity Registrant Name	SOUTHERN Co GAS
Entity Central Index Key	1,004,155
Entity Well-known Seasoned Issuer	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		100

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues:
Retail revenues			$ 15,234	$ 14,987	$ 15,550
Wholesale electric revenues			1,926	1,798	2,184
Other electric revenues			698	657	672
Natural gas revenues			1,596	0	0
Other revenues			442	47	61
Total operating revenues			19,896	17,489	18,467
Operating Expenses:
Fuel			4,361	4,750	6,005
Purchased power			750	645	672
Cost of natural gas			613	0	0
Cost of other sales			260	0	0
Other operations and maintenance			5,240	4,416	4,354
Depreciation and amortization			2,923	2,395	2,293
Depreciation and amortization			2,502	2,034	1,945
Taxes other than income taxes			1,113	997	981
Estimated loss on Kemper IGCC			428	365	868
Total operating expenses			15,267	13,207	14,825
Operating Income			4,629	4,282	3,642
Other Income and (Expense):
Allowance for equity funds used during construction			202	226	245
Earnings from equity method investments			59	0	0
Interest expense, net of amounts capitalized			(1,317)	(840)	(835)
Other income (expense), net			(93)	(39)	(44)
Total other income and (expense)			(1,149)	(653)	(634)
Earnings Before Income Taxes			3,480	3,629	3,008
Income taxes			951	1,194	977
Consolidated Net Income			2,529	2,435	2,031
Dividends on preferred and preference stock of subsidiaries			45	54	68
Net income attributable to noncontrolling interests			36	14	0
Consolidated Net Income Attributable to Southern Company			$ 2,448	$ 2,367	$ 1,963
Earnings per share (EPS) —
Basic EPS (in dollars per share)			$ 2.57	$ 2.60	$ 2.19
Diluted EPS (in dollars per share)			$ 2.55	$ 2.59	$ 2.18
Average number of shares of common stock outstanding — (in millions)
Basic shares			951	910	897
Diluted shares			958	914	901
Alabama Power [Member]
Operating Revenues:
Retail revenues			$ 5,322	$ 5,234	$ 5,249
Wholesale revenues, non-affiliates			283	241	281
Wholesale revenues, affiliates			69	84	189
Other revenues			215	209	223
Total operating revenues			5,889	5,768	5,942
Operating Expenses:
Fuel			1,297	1,342	1,605
Purchased power, non-affiliates			166	171	185
Purchased power, affiliates			168	180	200
Other operations and maintenance			1,510	1,501	1,468
Depreciation and amortization			844	780	724
Depreciation and amortization			703	643	603
Taxes other than income taxes			380	368	356
Total operating expenses			4,224	4,205	4,417
Operating Income			1,665	1,563	1,525
Other Income and (Expense):
Allowance for equity funds used during construction			28	60	49
Interest expense, net of amounts capitalized			(302)	(274)	(255)
Other income (expense), net			(21)	(32)	(7)
Total other income and (expense)			(295)	(246)	(213)
Earnings Before Income Taxes			1,370	1,317	1,312
Income taxes			531	506	512
Consolidated Net Income			839	811	800
Dividends on preferred and preference stock of subsidiaries			17	26	39
Consolidated Net Income Attributable to Southern Company			822	785	761
Georgia Power [Member]
Operating Revenues:
Retail revenues			7,772	7,727	8,240
Wholesale revenues, non-affiliates			175	215	335
Wholesale revenues, affiliates			42	20	42
Other revenues			394	364	371
Total operating revenues			8,383	8,326	8,988
Operating Expenses:
Fuel			1,807	2,033	2,547
Purchased power, non-affiliates			361	289	287
Purchased power, affiliates			518	575	701
Other operations and maintenance			1,960	1,844	1,902
Depreciation and amortization			1,063	1,029	1,019
Depreciation and amortization			855	846	846
Taxes other than income taxes			405	391	409
Total operating expenses			5,906	5,978	6,692
Operating Income			2,477	2,348	2,296
Other Income and (Expense):
Allowance for equity funds used during construction			48	40	45
Interest expense, net of amounts capitalized			(388)	(363)	(348)
Other income (expense), net			38	61	23
Total other income and (expense)			(350)	(302)	(325)
Earnings Before Income Taxes			2,127	2,046	1,971
Income taxes			780	769	729
Consolidated Net Income			1,347	1,277	1,242
Dividends on preferred and preference stock of subsidiaries			17	17	17
Consolidated Net Income Attributable to Southern Company			1,330	1,260	1,225
Gulf Power [Member]
Operating Revenues:
Retail revenues			1,281	1,249	1,267
Wholesale revenues, non-affiliates			61	107	129
Wholesale revenues, affiliates			75	58	130
Other revenues			68	69	64
Total operating revenues			1,485	1,483	1,590
Operating Expenses:
Fuel			432	445	605
Purchased power, non-affiliates			126	100	82
Purchased power, affiliates			16	35	25
Other operations and maintenance			336	354	341
Depreciation and amortization			179	152	153
Depreciation and amortization			172	141	145
Taxes other than income taxes			120	118	111
Total operating expenses			1,202	1,193	1,309
Operating Income			283	290	281
Other Income and (Expense):
Interest expense, net of amounts capitalized			(47)	(49)	(53)
Other income (expense), net			(5)	8	9
Total other income and (expense)			(52)	(41)	(44)
Earnings Before Income Taxes			231	249	237
Income taxes			91	92	88
Consolidated Net Income			140	157	149
Dividends on preferred and preference stock of subsidiaries			9	9	9
Consolidated Net Income Attributable to Southern Company			131	148	140
Mississippi Power [Member]
Operating Revenues:
Retail revenues			859	776	795
Wholesale revenues, non-affiliates			261	270	323
Wholesale revenues, affiliates			26	76	107
Other revenues			17	16	18
Total operating revenues			1,163	1,138	1,243
Operating Expenses:
Fuel			343	443	574
Purchased power, non-affiliates			5	5	18
Purchased power, affiliates			29	7	25
Other operations and maintenance			312	274	271
Depreciation and amortization			157	126	104
Depreciation and amortization			132	123	97
Taxes other than income taxes			109	94	79
Estimated loss on Kemper IGCC			428	365	868
Total operating expenses			1,358	1,311	1,932
Operating Income			(195)	(173)	(689)
Other Income and (Expense):
Allowance for equity funds used during construction			124	110	136
Interest expense, net of amounts capitalized			(74)	(7)	(45)
Other income (expense), net			(7)	(8)	(14)
Total other income and (expense)			43	95	77
Earnings Before Income Taxes			(152)	(78)	(612)
Income taxes			(104)	(72)	(285)
Consolidated Net Income			(48)	(6)	(327)
Dividends on preferred and preference stock of subsidiaries			2	2	2
Consolidated Net Income Attributable to Southern Company			(50)	(8)	(329)
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates			1,146	964	1,116
Wholesale revenues, affiliates			419	417	383
Other revenues			12	9	2
Total operating revenues			1,577	1,390	1,501
Operating Expenses:
Fuel			456	441	596
Purchased power, non-affiliates			81	72	105
Purchased power, affiliates			21	21	66
Other operations and maintenance			354	260	237
Depreciation and amortization			370	254	225
Depreciation and amortization			352	248	220
Taxes other than income taxes			23	22	22
Total operating expenses			1,287	1,064	1,246
Operating Income			290	326	255
Other Income and (Expense):
Interest expense, net of amounts capitalized			(117)	(77)	(89)
Other income (expense), net			6	1	6
Total other income and (expense)			(111)	(76)	(83)
Earnings Before Income Taxes			179	250	172
Income taxes			(195)	21	(3)
Consolidated Net Income			374	229	175
Net income attributable to noncontrolling interests			36	14	3
Net income attributable to Southern Power Company			$ 338	215	172
Predecessor [Member] | Southern Company Gas [Member]
Operating Revenues:
Natural gas revenues		$ 1,841		3,817	5,257
Other revenues		64		124	128
Total operating revenues		1,905		3,941	5,385
Operating Expenses:
Cost of natural gas		755		1,617	2,729
Cost of other sales		14		28	36
Other operations and maintenance		454		928	939
Depreciation and amortization		206		397	380
Taxes other than income taxes		99		181	208
Merger-related expenses		56		44	0
Total operating expenses		1,584		3,195	4,292
Gain on disposition of assets		0		0	2
Operating Income		321		746	1,095
Other Income and (Expense):
Earnings from equity method investments		2		6	8
Interest expense, net of amounts capitalized		(96)		(175)	(182)
Other income (expense), net		5		9	9
Total other income and (expense)		(89)		(160)	(165)
Earnings Before Income Taxes		232		586	930
Income taxes		87		213	350
Income from continuing operations		145		373	580
Loss from discontinued operations, net of tax		0		0	80
Consolidated Net Income		145		373	500
Net income attributable to noncontrolling interests		14		20	18
Consolidated Net Income Attributable to Southern Company		$ 131		$ 353	$ 482
Successor [Member] | Southern Company Gas [Member]
Operating Revenues:
Natural gas revenues	$ 1,596
Other revenues	56
Total operating revenues	1,652
Operating Expenses:
Cost of natural gas	613
Cost of other sales	10
Other operations and maintenance	482
Depreciation and amortization	238
Taxes other than income taxes	71
Merger-related expenses	41
Total operating expenses	1,455
Gain on disposition of assets	0
Operating Income	197
Other Income and (Expense):
Earnings from equity method investments	60
Interest expense, net of amounts capitalized	(81)
Other income (expense), net	14
Total other income and (expense)	(7)
Earnings Before Income Taxes	190
Income taxes	76
Income from continuing operations	114
Loss from discontinued operations, net of tax	0
Consolidated Net Income	114
Net income attributable to noncontrolling interests	0
Consolidated Net Income Attributable to Southern Company	$ 114

Consolidated Statements of Inc3

Consolidated Statements of Income (Parenthetical) - Southern Company Gas [Member] - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor [Member]
Excise Taxes Collected	$ 32
Predecessor [Member]
Excise Taxes Collected		$ 57	$ 103	$ 133

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Net Income			$ 2,529	$ 2,435	$ 2,031
Qualifying hedges:
Changes in fair value, net of tax			(136)	(13)	(10)
Reclassification adjustment for amounts included in net income, net of tax			69	6	5
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax			13	(2)	(51)
Reclassification adjustment for amounts included in net income, net of tax			4	7	3
Total other comprehensive income (loss)			(50)	(2)	(53)
Dividends on preferred and preference stock of subsidiaries			45	54	68
Comprehensive income attributable to noncontrolling interests			36	14	0
Comprehensive Income			2,398	2,365	1,910
Alabama Power [Member]
Consolidated Net Income			839	811	800
Qualifying hedges:
Changes in fair value, net of tax			(2)	(5)	(5)
Reclassification adjustment for amounts included in net income, net of tax			4	2	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)			2	(3)	(3)
Dividends on preferred and preference stock of subsidiaries			17	26	39
Comprehensive Income			841	808	797
Georgia Power [Member]
Consolidated Net Income			1,347	1,277	1,242
Qualifying hedges:
Changes in fair value, net of tax			0	(9)	(5)
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)			2	(7)	(3)
Dividends on preferred and preference stock of subsidiaries			17	17	17
Comprehensive Income			1,349	1,270	1,239
Gulf Power [Member]
Consolidated Net Income			140	157	149
Qualifying hedges:
Changes in fair value, net of tax			1	1	0
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)			1	1	0
Dividends on preferred and preference stock of subsidiaries			9	9	9
Comprehensive Income			141	158	149
Mississippi Power [Member]
Consolidated Net Income			(48)	(6)	(327)
Qualifying hedges:
Changes in fair value, net of tax			1	0	0
Reclassification adjustment for amounts included in net income, net of tax			1	1	1
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)			2	1	1
Dividends on preferred and preference stock of subsidiaries			2	2	2
Comprehensive Income			(46)	(5)	(326)
Southern Power [Member]
Consolidated Net Income			374	229	175
Qualifying hedges:
Changes in fair value, net of tax			(27)	0	0
Reclassification adjustment for amounts included in net income, net of tax			58	1	0
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)			31	1	0
Comprehensive income attributable to noncontrolling interests			36	14	3
Comprehensive Income			$ 369	216	172
Successor [Member] | Southern Company Gas [Member]
Consolidated Net Income	$ 114
Qualifying hedges:
Changes in fair value, net of tax	(1)
Reclassification adjustment for amounts included in net income, net of tax	0
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax	27
Reclassification adjustment for amounts included in net income, net of tax	0
Total other comprehensive income (loss)	26
Comprehensive income attributable to noncontrolling interests	0
Comprehensive Income	$ 140
Predecessor [Member] | Southern Company Gas [Member]
Consolidated Net Income		$ 145		373	500
Qualifying hedges:
Changes in fair value, net of tax		(41)		0	(6)
Reclassification adjustment for amounts included in net income, net of tax		1		8	(3)
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax		0		0	(71)
Reclassification adjustment for amounts included in net income, net of tax		5		12	8
Total other comprehensive income (loss)		(35)		20	(72)
Comprehensive income attributable to noncontrolling interests		14		20	16
Comprehensive Income		$ 96		$ 373	$ 412

Consolidated Statements of Com5

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualifying hedges change in fair value tax			$ (84)	$ (8)	$ (6)
Qualifying hedges reclassification adjustment tax			43	4	3
Pension and other postretirement benefit plans gain (loss) tax			10	(1)	(32)
Pension and other postretirement benefit plans reclassification adjustment tax			3	4	2
Alabama Power [Member]
Qualifying hedges change in fair value tax			(1)	(3)	(3)
Qualifying hedges reclassification adjustment tax			2	1	1
Georgia Power [Member]
Qualifying hedges change in fair value tax			0	(6)	(3)
Qualifying hedges reclassification adjustment tax			2	1	1
Gulf Power [Member]
Qualifying hedges change in fair value tax			0	0	0
Mississippi Power [Member]
Qualifying hedges change in fair value tax			1	0	0
Qualifying hedges reclassification adjustment tax			1	1	1
Southern Power [Member]
Qualifying hedges change in fair value tax			(17)	0	0
Qualifying hedges reclassification adjustment tax			$ 36	0	0
Successor [Member] | Southern Company Gas [Member]
Qualifying hedges change in fair value tax	$ (1)
Qualifying hedges reclassification adjustment tax	0
Pension and other postretirement benefit plans gain (loss) tax	19
Pension and other postretirement benefit plans reclassification adjustment tax	$ 0
Predecessor [Member] | Southern Company Gas [Member]
Qualifying hedges change in fair value tax		$ (23)		(3)	(2)
Qualifying hedges reclassification adjustment tax		0		1	(2)
Pension and other postretirement benefit plans gain (loss) tax		0		0	(48)
Pension and other postretirement benefit plans reclassification adjustment tax		$ 4		$ 9	$ 5

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Activities:
Consolidated Net Income	$ 2,529,000,000	$ 2,435,000,000	$ 2,031,000,000
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	2,923,000,000	2,395,000,000	2,293,000,000
Deferred income taxes	(127,000,000)	1,404,000,000	709,000,000
Amortization of investment tax credits	(22,000,000)	(21,000,000)	(22,000,000)
Collateral deposits	(102,000,000)	0	0
Allowance for equity funds used during construction	(202,000,000)	(226,000,000)	(245,000,000)
Pension, postretirement, and other employee benefits	(65,000,000)	83,000,000	(9,000,000)
Pension and postretirement funding	(1,029,000,000)	(7,000,000)	(506,000,000)
Settlement of asset retirement obligations	(171,000,000)	(37,000,000)	(17,000,000)
Stock based compensation expense	121,000,000	99,000,000	63,000,000
Hedge Settlements	(233,000,000)	(17,000,000)	0
Estimated loss on Kemper IGCC	428,000,000	365,000,000	868,000,000
Income taxes receivable, non-current	(122,000,000)	(413,000,000)	0
Other, net	(36,000,000)	(33,000,000)	13,000,000
Changes in certain current assets and liabilities --
-Receivables	(544,000,000)	243,000,000	(352,000,000)
-Fossil fuel for generation	178,000,000	61,000,000	408,000,000
-Natural gas for sale	(226,000,000)	0	0
-Materials and supplies	(31,000,000)	(44,000,000)	(67,000,000)
-Other current assets	(174,000,000)	(108,000,000)	(57,000,000)
-Accounts payable	301,000,000	(353,000,000)	267,000,000
-Accrued taxes	1,456,000,000	352,000,000	(105,000,000)
-Accrued compensation	36,000,000	(41,000,000)	255,000,000
-Mirror CWIP	0	(271,000,000)	180,000,000
-Other current liabilities	215,000,000	98,000,000	109,000,000
-Retail fuel cost over-recovery—short-term	(231,000,000)	289,000,000	(23,000,000)
Net cash provided from operating activities	4,894,000,000	6,274,000,000	5,815,000,000
Investing Activities:
Business acquisitions, net of cash acquired	(10,689,000,000)	(1,719,000,000)	(731,000,000)
Property additions	(7,310,000,000)	(5,674,000,000)	(5,246,000,000)
Investment in restricted cash	(733,000,000)	(160,000,000)	(11,000,000)
Distribution of restricted cash	742,000,000	154,000,000	57,000,000
Nuclear decommissioning trust fund purchases	(1,160,000,000)	(1,424,000,000)	(916,000,000)
Nuclear decommissioning trust fund sales	1,154,000,000	1,418,000,000	914,000,000
Cost of removal, net of salvage	(245,000,000)	(167,000,000)	(170,000,000)
Change in construction payables	(121,000,000)	402,000,000	(107,000,000)
Investment in unconsolidated subsidiaries	(1,444,000,000)	0	0
Prepaid long-term service agreement	(134,000,000)	(197,000,000)	(181,000,000)
Other investing activities	(108,000,000)	87,000,000	(17,000,000)
Net cash used for investing activities	(20,048,000,000)	(7,280,000,000)	(6,408,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	1,228,000,000	73,000,000	(676,000,000)
Proceeds --
Long-term debt	16,368,000,000	7,029,000,000	3,169,000,000
Interest-bearing refundable deposit	0	0	125,000,000
Common stock issuances	3,758,000,000	256,000,000	806,000,000
Short-term borrowings	0	755,000,000	0
Redemptions and repurchases --
Long-term debt	(3,145,000,000)	(3,604,000,000)	(816,000,000)
Common stock repurchased	0	(115,000,000)	(5,000,000)
Interest-bearing refundable deposits	0	(275,000,000)	0
Preferred and preference stock	0	(412,000,000)	0
Short-term borrowings	(478,000,000)	(255,000,000)	0
Payment of common stock dividends	(2,104,000,000)	(1,959,000,000)	(1,866,000,000)
Distributions to noncontrolling interests	(72,000,000)	(18,000,000)	(1,000,000)
Capital contributions from noncontrolling interests	682,000,000	341,000,000	8,000,000
Purchase of Membership Interests from Noncontrolling Interests	(129,000,000)	0	0
Other financing activities	(383,000,000)	(116,000,000)	(100,000,000)
Net cash provided from (used for) financing activities	15,725,000,000	1,700,000,000	644,000,000
Net Change in Cash and Cash Equivalents	571,000,000	694,000,000	51,000,000
Cash and Cash Equivalents at Beginning of Year	1,404,000,000	710,000,000	659,000,000
Cash and Cash Equivalents at End of Year	1,975,000,000	1,404,000,000	710,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,100,000,000	809,000,000	732,000,000
Income taxes (net of refunds)	(148,000,000)	(9,000,000)	272,000,000
Noncash transactions -
Accrued property additions at year-end	1,500,000,000	844,000,000	528,000,000
Alabama Power [Member]
Operating Activities:
Consolidated Net Income	839,000,000	811,000,000	800,000,000
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	844,000,000	780,000,000	724,000,000
Deferred income taxes	407,000,000	388,000,000	270,000,000
Amortization of investment tax credits	(8,000,000)	(8,000,000)	(8,000,000)
Allowance for equity funds used during construction	(28,000,000)	(60,000,000)	(49,000,000)
Pension, postretirement, and other employee benefits	(27,000,000)	20,000,000	(61,000,000)
Pension and postretirement funding	(133,000,000)	0	0
Other deferred charges - affiliated	(50,000,000)	0	0
Other, net	(25,000,000)	(5,000,000)	29,000,000
Changes in certain current assets and liabilities --
-Receivables	94,000,000	(160,000,000)	(58,000,000)
-Fossil fuel for generation	34,000,000	28,000,000	61,000,000
-Other current assets	(33,000,000)	12,000,000	(29,000,000)
-Accounts payable	73,000,000	3,000,000	157,000,000
-Accrued taxes	93,000,000	138,000,000	(199,000,000)
-Other current liabilities	23,000,000	(4,000,000)	59,000,000
-Retail fuel cost over-recovery—short-term	(162,000,000)	191,000,000	5,000,000
Net cash provided from operating activities	1,949,000,000	2,142,000,000	1,709,000,000
Investing Activities:
Property additions	(1,272,000,000)	(1,367,000,000)	(1,457,000,000)
Nuclear decommissioning trust fund purchases	(352,000,000)	(439,000,000)	(245,000,000)
Nuclear decommissioning trust fund sales	351,000,000	438,000,000	244,000,000
Cost of removal, net of salvage	(94,000,000)	(71,000,000)	(77,000,000)
Change in construction payables	(37,000,000)	(15,000,000)	(10,000,000)
Other investing activities	(34,000,000)	(34,000,000)	(22,000,000)
Net cash used for investing activities	(1,438,000,000)	(1,488,000,000)	(1,567,000,000)
Proceeds --
Capital contributions from parent company	260,000,000	22,000,000	28,000,000
Senior notes	400,000,000	975,000,000	400,000,000
Pollution control revenue bonds	0	80,000,000	254,000,000
Other long-term debt	45,000,000	0	0
Redemptions and repurchases --
Preferred and preference stock	0	(412,000,000)	0
Senior notes	(200,000,000)	(650,000,000)	0
Pollution control revenue bonds	0	(134,000,000)	(254,000,000)
Payment of common stock dividends	(765,000,000)	(571,000,000)	(550,000,000)
Other financing activities	(25,000,000)	(43,000,000)	(42,000,000)
Net cash provided from (used for) financing activities	(285,000,000)	(733,000,000)	(164,000,000)
Net Change in Cash and Cash Equivalents	226,000,000	(79,000,000)	(22,000,000)
Cash and Cash Equivalents at Beginning of Year	194,000,000	273,000,000	295,000,000
Cash and Cash Equivalents at End of Year	420,000,000	194,000,000	273,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	277,000,000	250,000,000	231,000,000
Income taxes (net of refunds)	(108,000,000)	121,000,000	436,000,000
Noncash transactions -
Accrued property additions at year-end	84,000,000	121,000,000	8,000,000
Georgia Power [Member]
Operating Activities:
Consolidated Net Income	1,347,000,000	1,277,000,000	1,242,000,000
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	1,063,000,000	1,029,000,000	1,019,000,000
Deferred income taxes	383,000,000	173,000,000	352,000,000
Amortization of investment tax credits	(10,000,000)	(10,000,000)	(10,000,000)
Allowance for equity funds used during construction	(48,000,000)	(40,000,000)	(45,000,000)
Retail fuel cost-recovery - long-term	0	106,000,000	(44,000,000)
Pension and postretirement funding	(287,000,000)	(7,000,000)	(156,000,000)
Settlement of asset retirement obligations	(123,000,000)	(29,000,000)	(12,000,000)
Other deferred charges - affiliated	(111,000,000)	0	0
Other, net	(10,000,000)	10,000,000	70,000,000
Changes in certain current assets and liabilities --
-Receivables	60,000,000	187,000,000	(248,000,000)
-Fossil fuel for generation	104,000,000	37,000,000	303,000,000
-Prepaid income taxes	0	89,000,000	(216,000,000)
-Other current assets	(38,000,000)	(62,000,000)	(37,000,000)
-Accounts payable	(42,000,000)	(259,000,000)	16,000,000
-Accrued taxes	131,000,000	25,000,000	17,000,000
-Accrued compensation	(5,000,000)	(17,000,000)	62,000,000
-Other current liabilities	1,000,000	(2,000,000)	40,000,000
Net cash provided from operating activities	2,425,000,000	2,517,000,000	2,363,000,000
Investing Activities:
Property additions	(2,223,000,000)	(2,091,000,000)	(2,023,000,000)
Nuclear decommissioning trust fund purchases	(808,000,000)	(985,000,000)	(671,000,000)
Nuclear decommissioning trust fund sales	803,000,000	980,000,000	669,000,000
Cost of removal, net of salvage	(83,000,000)	(71,000,000)	(65,000,000)
Change in construction payables, net of joint owner portion	(35,000,000)	217,000,000	(54,000,000)
Prepaid long-term service agreement	(34,000,000)	(66,000,000)	(70,000,000)
Sale of property	10,000,000	70,000,000	7,000,000
Other investing activities	23,000,000	2,000,000	1,000,000
Net cash used for investing activities	(2,347,000,000)	(1,944,000,000)	(2,206,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	234,000,000	2,000,000	(891,000,000)
Proceeds --
Capital contributions from parent company	594,000,000	62,000,000	549,000,000
Short-term borrowings	0	250,000,000	0
Senior notes	650,000,000	500,000,000	0
Pollution control revenue bonds	0	409,000,000	40,000,000
FFB loan	425,000,000	1,000,000,000	1,200,000,000
Redemptions and repurchases --
Short-term borrowings	0	(250,000,000)	0
Senior notes	(700,000,000)	(1,175,000,000)	0
Pollution control revenue bonds	(4,000,000)	(268,000,000)	(37,000,000)
Payment of common stock dividends	(1,305,000,000)	(1,034,000,000)	(954,000,000)
Other financing activities	(36,000,000)	(26,000,000)	(70,000,000)
Net cash provided from (used for) financing activities	(142,000,000)	(530,000,000)	(163,000,000)
Net Change in Cash and Cash Equivalents	(64,000,000)	43,000,000	(6,000,000)
Cash and Cash Equivalents at Beginning of Year	67,000,000	24,000,000	30,000,000
Cash and Cash Equivalents at End of Year	3,000,000	67,000,000	24,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	375,000,000	353,000,000	319,000,000
Income taxes (net of refunds)	170,000,000	506,000,000	507,000,000
Noncash transactions -
Accrued property additions at year-end	336,000,000	387,000,000	154,000,000
Capital lease obligation	0	149,000,000	0
Gulf Power [Member]
Operating Activities:
Consolidated Net Income	140,000,000	157,000,000	149,000,000
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	179,000,000	152,000,000	153,000,000
Deferred income taxes	57,000,000	90,000,000	65,000,000
Pension and postretirement funding	(48,000,000)	0	(30,000,000)
Other, net	(3,000,000)	4,000,000	(4,000,000)
Changes in certain current assets and liabilities --
-Receivables	15,000,000	33,000,000	(17,000,000)
-Fossil fuel for generation	37,000,000	(6,000,000)	34,000,000
-Prepaid income taxes	(11,000,000)	32,000,000	(19,000,000)
-Other current assets	(1,000,000)	(2,000,000)	(2,000,000)
-Accounts payable	5,000,000	(22,000,000)	8,000,000
-Over recovered regulatory clause revenues	1,000,000	22,000,000	0
-Other current liabilities	8,000,000	0	7,000,000
Net cash provided from operating activities	379,000,000	460,000,000	344,000,000
Investing Activities:
Property additions	(178,000,000)	(235,000,000)	(348,000,000)
Cost of removal, net of salvage	(9,000,000)	(10,000,000)	(13,000,000)
Change in construction payables	13,000,000	(28,000,000)	12,000,000
Payments Pursuant to Long Term Service Agreements	5,000,000	8,000,000	8,000,000
Other investing activities	(1,000,000)	0	(1,000,000)
Net cash used for investing activities	(180,000,000)	(281,000,000)	(358,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	126,000,000	32,000,000	(26,000,000)
Proceeds --
Capital contributions from parent company	20,000,000	4,000,000	4,000,000
Common stock issuances	0	20,000,000	50,000,000
Senior notes	0	0	200,000,000
Pollution control revenue bonds	0	13,000,000	42,000,000
Redemptions and repurchases --
Senior notes	(235,000,000)	(60,000,000)	(75,000,000)
Pollution control revenue bonds	0	(13,000,000)	(29,000,000)
Payment of common stock dividends	(120,000,000)	(130,000,000)	(123,000,000)
Other financing activities	(8,000,000)	(10,000,000)	(12,000,000)
Net cash provided from (used for) financing activities	(217,000,000)	(144,000,000)	31,000,000
Net Change in Cash and Cash Equivalents	(18,000,000)	35,000,000	17,000,000
Cash and Cash Equivalents at Beginning of Year	74,000,000	39,000,000	22,000,000
Cash and Cash Equivalents at End of Year	56,000,000	74,000,000	39,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	53,000,000	52,000,000	48,000,000
Income taxes (net of refunds)	21,000,000	(7,000,000)	44,000,000
Noncash transactions -
Accrued property additions at year-end	33,000,000	20,000,000	42,000,000
Mississippi Power [Member]
Operating Activities:
Consolidated Net Income	(48,000,000)	(6,000,000)	(327,000,000)
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	157,000,000	126,000,000	104,000,000
Deferred income taxes	(67,000,000)	777,000,000	145,000,000
Investment tax credits	0	(210,000,000)	(38,000,000)
Amortization of investment tax credits	(1,000,000)	(1,000,000)	(1,000,000)
Allowance for equity funds used during construction	(124,000,000)	(110,000,000)	(136,000,000)
Pension and postretirement funding	(47,000,000)	0	(33,000,000)
Regulatory assets associated with Kemper IGCC	(12,000,000)	(61,000,000)	(72,000,000)
Estimated loss on Kemper IGCC	428,000,000	365,000,000	868,000,000
Income taxes receivable, non-current	0	(544,000,000)	0
Other, net	(20,000,000)	8,000,000	22,000,000
Changes in certain current assets and liabilities --
-Receivables	13,000,000	28,000,000	(22,000,000)
-Prepaid income taxes	39,000,000	(35,000,000)	(50,000,000)
-Other current assets	(8,000,000)	(18,000,000)	(6,000,000)
-Accounts payable	(14,000,000)	(34,000,000)	33,000,000
-Accrued taxes	14,000,000	(11,000,000)	39,000,000
-Over recovered regulatory clause revenues	(45,000,000)	96,000,000	(18,000,000)
-Mirror CWIP	0	(271,000,000)	180,000,000
-Customer liability associated with Kemper refunds	(73,000,000)	73,000,000	0
-Other current liabilities	36,000,000	0	46,000,000
Net cash provided from operating activities	229,000,000	173,000,000	735,000,000
Investing Activities:
Property additions	(798,000,000)	(857,000,000)	(1,257,000,000)
Investment in restricted cash	0	0	(11,000,000)
Distribution of restricted cash	0	0	11,000,000
Change in construction payables	(26,000,000)	(9,000,000)	(50,000,000)
Government grant proceeds	137,000,000	0	0
Other investing activities	(10,000,000)	(40,000,000)	(33,000,000)
Net cash used for investing activities	(697,000,000)	(906,000,000)	(1,340,000,000)
Proceeds --
Capital contributions from parent company	627,000,000	277,000,000	451,000,000
Bonds-Other	0	0	23,000,000
Interest-bearing refundable deposit	0	0	125,000,000
Short-term borrowings	0	505,000,000	0
Other long-term debt	1,200,000,000	0	250,000,000
Long-term debt issuance to parent company	200,000,000	275,000,000	220,000,000
Redemptions and repurchases --
Short-term borrowings	(478,000,000)	(5,000,000)	0
Senior notes	(300,000,000)	0	0
Bonds-Other	0	0	(34,000,000)
Long-term debt redemption to parent company	(225,000,000)	0	(220,000,000)
Other long-term debt	(425,000,000)	(350,000,000)	0
Return of paid in capital	0	0	(220,000,000)
Other financing activities	(5,000,000)	(4,000,000)	(2,000,000)
Net cash provided from (used for) financing activities	594,000,000	698,000,000	593,000,000
Net Change in Cash and Cash Equivalents	126,000,000	(35,000,000)	(12,000,000)
Cash and Cash Equivalents at Beginning of Year	98,000,000	133,000,000	145,000,000
Cash and Cash Equivalents at End of Year	224,000,000	98,000,000	133,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	50,000,000	45,000,000	7,000,000
Income taxes (net of refunds)	(97,000,000)	(33,000,000)	(379,000,000)
Noncash transactions -
Accrued property additions at year-end	78,000,000	105,000,000	114,000,000
Issuance of Promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest	0	301,000,000	0
Southern Power [Member]
Operating Activities:
Consolidated Net Income	374,000,000	229,000,000	175,000,000
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	370,000,000	254,000,000	225,000,000
Deferred income taxes	(1,063,000,000)	42,000,000	(168,000,000)
Investment tax credits	0	162,000,000	74,000,000
Amortization of investment tax credits	(37,000,000)	(19,000,000)	(11,000,000)
Collateral deposits	(102,000,000)	0	0
Accrued income taxes, non-current	(109,000,000)	109,000,000	0
Other, net	0	(2,000,000)	(10,000,000)
Changes in certain current assets and liabilities --
-Receivables	(54,000,000)	18,000,000	(26,000,000)
-Prepaid income taxes	(29,000,000)	(26,000,000)	35,000,000
-Other current assets	4,000,000	(4,000,000)	(8,000,000)
-Accounts payable	27,000,000	(19,000,000)	30,000,000
-Accrued taxes	940,000,000	269,000,000	284,000,000
-Other current liabilities	18,000,000	(10,000,000)	3,000,000
Net cash provided from operating activities	339,000,000	1,003,000,000	603,000,000
Investing Activities:
Business acquisitions, net of cash acquired	(2,294,000,000)	(1,719,000,000)	(731,000,000)
Property additions	(2,114,000,000)	(1,005,000,000)	(21,000,000)
Investment in restricted cash	(733,000,000)	(159,000,000)	0
Distribution of restricted cash	736,000,000	154,000,000	0
Change in construction payables, net of joint owner portion	(57,000,000)	251,000,000	0
Payments pursuant to long-term service agreements	(350,000,000)	(82,000,000)	(61,000,000)
Other investing activities	15,000,000	22,000,000	(1,000,000)
Net cash used for investing activities	(4,797,000,000)	(2,538,000,000)	(814,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	73,000,000	(58,000,000)	195,000,000
Proceeds --
Capital contributions from parent company	1,850,000,000	646,000,000	146,000,000
Senior notes	2,831,000,000	1,650,000,000	0
Other long-term debt	65,000,000	402,000,000	10,000,000
Redemptions and repurchases --
Senior notes	(200,000,000)	(525,000,000)	0
Payment of common stock dividends	(272,000,000)	(131,000,000)	(131,000,000)
Other long-term debt	(86,000,000)	(4,000,000)	(10,000,000)
Distributions to noncontrolling interests	(57,000,000)	(18,000,000)	(1,000,000)
Capital contributions from noncontrolling interests	682,000,000	341,000,000	8,000,000
Purchase of Membership Interests from Noncontrolling Interests	(129,000,000)	0	0
Other financing activities	(30,000,000)	(13,000,000)	0
Net cash provided from (used for) financing activities	4,727,000,000	2,290,000,000	217,000,000
Net Change in Cash and Cash Equivalents	269,000,000	755,000,000	6,000,000
Cash and Cash Equivalents at Beginning of Year	830,000,000	75,000,000	69,000,000
Cash and Cash Equivalents at End of Year	1,099,000,000	830,000,000	75,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	89,000,000	74,000,000	85,000,000
Income taxes (net of refunds)	116,000,000	(518,000,000)	(220,000,000)
Noncash transactions -
Accrued property additions at year-end	251,000,000	257,000,000	1,000,000
Acquisitions	461,000,000	0	229,000,000
Capital contributions from noncontrolling interests	0	0	221,000,000
Successor [Member] | Southern Company Gas [Member]
Redemptions and repurchases --
Cash and Cash Equivalents at End of Year	19,000,000
Predecessor [Member] | Southern Company Gas [Member]
Operating Activities:
Consolidated Net Income		373,000,000	500,000,000
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total		397,000,000	380,000,000
Deferred income taxes		211,000,000	199,000,000
Amortization of investment tax credits		(2,000,000)	(2,000,000)
Pension, postretirement, and other employee benefits		24,000,000	19,000,000
Pension and postretirement funding		0	0
Stock based compensation expense		34,000,000	19,000,000
Hedge Settlements		0	0
Goodwill impairment		14,000,000	0
Mark-to-market adjustments		22,000,000	(155,000,000)
Loss on discontinued operations, net of tax		0	80,000,000
Other, net		43,000,000	(28,000,000)
Changes in certain current assets and liabilities --
-Receivables		615,000,000	(53,000,000)
-Prepaid income taxes		23,000,000	(175,000,000)
-Natural gas for sale		72,000,000	(58,000,000)
-Other current assets		(11,000,000)	44,000,000
-Accounts payable		(434,000,000)	25,000,000
-Accrued taxes		(20,000,000)	(66,000,000)
-Accrued compensation		(6,000,000)	31,000,000
Other current liabilities		24,000,000	(97,000,000)
Net cash used for operating activities of discontinued operations		0	(10,000,000)
Net cash provided from operating activities		1,381,000,000	655,000,000
Investing Activities:
Property additions		(961,000,000)	(702,000,000)
Cost of removal, net of salvage		(84,000,000)	(39,000,000)
Change in construction payables		18,000,000	(28,000,000)
Investment in unconsolidated subsidiaries		(12,000,000)	(3,000,000)
Disposition of assets		0	230,000,000
Other investing activities		12,000,000	50,000,000
Net cash used for investing activities of discontinued operations		0	(13,000,000)
Net cash used for investing activities		(1,027,000,000)	(505,000,000)
Financing Activities:
Increase (decrease) in notes payable, net		(165,000,000)	4,000,000
Proceeds --
First Mortgage Bonds		0	0
Capital contributions from parent company		0	0
Senior notes		250,000,000	0
Redemptions and repurchases --
First Mortgage Bonds		0	0
Senior notes		(200,000,000)	0
Payment of common stock dividends		(244,000,000)	(233,000,000)
Distributions to noncontrolling interests		(18,000,000)	(17,000,000)
Purchase of 15% noncontrolling interest in SouthStar		0	0
Other financing activities		11,000,000	22,000,000
Net cash provided from (used for) financing activities		(366,000,000)	(224,000,000)
Net Change in Cash and Cash Equivalents — Continuing Operations		(12,000,000)	(51,000,000)
Net Change in Cash and Cash Equivalents — Discontinued Operations		0	(23,000,000)
Cash and Cash Equivalents at Beginning of Year	$ 19,000,000	31,000,000	105,000,000
Cash and Cash Equivalents at End of Year		19,000,000	31,000,000
Supplemental Cash Flow Information:
Interest, net of amounts capitalized		181,000,000	187,000,000
Income taxes (net of refunds)		(26,000,000)	422,000,000
Noncash transactions -
Accrued property additions at year-end		$ 48,000,000	$ 31,000,000

Consolidated Statements of Cas7

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net cash paid for capitalized interest		$ 125	$ 124	$ 111
Alabama Power [Member]
Net cash paid for capitalized interest		11	22	18
Georgia Power [Member]
Net cash paid for capitalized interest		20	16	18
Gulf Power [Member]
Net cash paid for capitalized interest		0	6	5
Mississippi Power [Member]
Net cash paid for capitalized interest		49	66	69
Southern Power [Member]
Net cash paid for capitalized interest		$ 44	$ 14	$ 0
Southern Company Gas [Member] | Successor [Member] | Southstar [Member]
Ownership percentage of noncontrolling interest	15.00%

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 1,975	$ 1,404
Receivables --
Customer accounts receivable	1,565	1,058
Energy marketing receivable	623	0
Unbilled revenues	706	397
Under recovered regulatory clause revenues	18	63
Income taxes receivable, current	544	144
Other accounts and notes receivable	377	398
Accumulated provision for uncollectible accounts	(43)	(13)
Materials and supplies	1,462	1,061
Fossil fuel for generation	689	868
Natural gas for sale	631	0
Prepaid expenses	364	495
Other regulatory assets, current	581	580
Other current assets	230	71
Total current assets	9,722	6,526
Property, Plant, and Equipment:
In service	98,416	75,118
Less accumulated depreciation	29,852	24,253
Plant in service, net of depreciation	68,564	50,865
Other utility plant, net	0	233
Nuclear fuel, at amortized cost	905	934
Construction work in progress	8,977	9,082
Total property, plant, and equipment	78,446	61,114
Other Property and Investments:
Goodwill	6,251	2
Equity investments in unconsolidated subsidiaries	1,549	6
Other intangible assets, net of amortization	970	317
Nuclear decommissioning trusts, at fair value	1,606	1,512
Leveraged leases	774	755
Miscellaneous property and investments	270	160
Total other property and investments	11,420	2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,629	1,560
Unamortized loss on reacquired debt	223	227
Other regulatory assets, deferred	6,851	4,989
Income taxes receivable, non-current	11	413
Accumulated deferred income taxes – assets	52	56
Other deferred charges and assets	1,395	737
Total deferred charges and other assets	10,109	7,926
Total Assets	109,697	78,318
Current Liabilities:
Securities due within one year, Other	2,587	2,674
Notes payable	2,241	1,376
Energy marketing trade payables	597	0
Accounts payable	2,228	1,905
Customer deposits	558	404
Accrued taxes --
Accrued income taxes	193	9
Unrecognized tax benefits	385	10
Other accrued taxes	667	484
Accrued interest	518	249
Accrued compensation	915	777
Asset retirement obligations, current	378	217
Liabilities from risk management activities, net of collateral	107	156
Acquisitions Payable	489	0
Other regulatory liabilities, current	236	278
Over recovered regulatory clause revenues, current	135	106
Other current liabilities	683	484
Total current liabilities	12,917	9,129
Long-Term Debt
Unamortized debt issuance expense	(213)	(241)
Long-term Debt	42,629	24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	14,092	12,322
Deferred credits related to income taxes	219	187
Accumulated deferred investment tax credits	2,228	1,219
Employee benefit obligations	2,299	2,582
Asset retirement obligations, deferred	4,136	3,542
Unrecognized tax benefits, deferred	0	370
Accrued environmental remediation	397	42
Other cost of removal obligations	2,748	1,162
Other regulatory liabilities, deferred	258	254
Other deferred credits and liabilities	880	678
Total deferred credits and other liabilities	27,257	22,358
Total Liabilities	82,803	56,175
Redeemable Preferred Stock of Subsidiaries	118	118
Redeemable Noncontrolling Interests	164	43
Commitments and Contingent Matters
Common Stockholders' Equity:
Common stock	4,952	4,572
Paid-in capital	9,661	6,282
Retained earnings	10,356	10,010
Accumulated other comprehensive loss	(180)	(130)
Common Stockholders' Equity	24,758	20,592
Noncontrolling interests	1,854	1,390
Total stockholders' equity	26,612	21,982
Total Liabilities and Stockholders' Equity	109,697	78,318
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	420	194
Receivables --
Customer accounts receivable	348	375
Unbilled revenues	146	119
Income taxes receivable, current	0	142
Other accounts and notes receivable	27	20
Affiliated	40	50
Accumulated provision for uncollectible accounts	(10)	(10)
Materials and supplies	435	398
Fossil fuel for generation	205	239
Prepaid expenses	34	83
Other regulatory assets, current	149	182
Other current assets	11	9
Total current assets	1,805	1,801
Property, Plant, and Equipment:
In service	26,031	24,750
Less accumulated depreciation	9,112	8,736
Plant in service, net of depreciation	16,919	16,014
Nuclear fuel, at amortized cost	336	363
Construction work in progress	491	801
Total property, plant, and equipment	17,746	17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	66	71
Nuclear decommissioning trusts, at fair value	792	737
Miscellaneous property and investments	112	96
Total other property and investments	970	904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	525	522
Deferred under recovered regulatory clause revenues	150	99
Other regulatory assets, deferred	1,157	1,114
Other deferred charges and assets	163	103
Total deferred charges and other assets	1,995	1,838
Total Assets	22,516	21,721
Current Liabilities:
Securities due within one year, Other	561	200
Notes payable	0	0
Accounts payable - Affiliated	297	278
Accounts payable - Other	433	410
Customer deposits	88	88
Accrued taxes --
Accrued income taxes	45	0
Other accrued taxes	42	38
Accrued interest	78	73
Accrued compensation	193	175
Other regulatory liabilities, current	85	240
Other current liabilities	76	93
Total current liabilities	1,898	1,595
Long-Term Debt
Unamortized debt premium (discount), net	(9)	(9)
Unamortized debt issuance expense	(46)	(45)
Long-term Debt	6,535	6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,654	4,241
Deferred credits related to income taxes	65	70
Accumulated deferred investment tax credits	110	118
Employee benefit obligations	300	388
Asset retirement obligations, deferred	1,503	1,448
Other cost of removal obligations	684	722
Other regulatory liabilities, deferred	100	136
Other deferred credits and liabilities	63	76
Total deferred credits and other liabilities	7,479	7,199
Total Liabilities	15,912	15,448
Redeemable Preferred Stock of Subsidiaries	85	85
Redeemable Preferred Stock	85	85
Commitments and Contingent Matters
Common Stockholders' Equity:
Common stock	1,222	1,222
Paid-in capital	2,613	2,341
Retained earnings	2,518	2,461
Accumulated other comprehensive loss	(30)	(32)
Common Stockholders' Equity	6,323	5,992
Preference Stock	196	196
Total stockholders' equity	6,323	5,992
Total Liabilities and Stockholders' Equity	22,516	21,721
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	3	67
Receivables --
Customer accounts receivable	523	541
Unbilled revenues	224	188
Joint owner accounts receivable	57	227
Income taxes receivable, current	0	114
Other accounts and notes receivable	81	57
Affiliated	18	18
Accumulated provision for uncollectible accounts	(3)	(2)
Materials and supplies	479	449
Fossil fuel for generation	298	402
Prepaid expenses	105	230
Other regulatory assets, current	193	213
Other current assets	38	19
Total current assets	2,016	2,523
Property, Plant, and Equipment:
In service	33,841	31,841
Less accumulated depreciation	11,317	10,903
Plant in service, net of depreciation	22,524	20,938
Other utility plant, net	0	171
Nuclear fuel, at amortized cost	569	572
Construction work in progress	4,939	4,775
Total property, plant, and equipment	28,032	26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	60	64
Nuclear decommissioning trusts, at fair value	814	775
Miscellaneous property and investments	46	43
Total other property and investments	920	882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	676	679
Other regulatory assets, deferred	2,774	2,152
Other deferred charges and assets	417	173
Total deferred charges and other assets	3,867	3,004
Total Assets	34,835	32,865
Current Liabilities:
Securities due within one year, Other	460	712
Notes payable	391	158
Accounts payable - Affiliated	438	411
Accounts payable - Other	589	750
Customer deposits	265	264
Accrued taxes --
Accrued income taxes	17	12
Other accrued taxes	390	325
Accrued interest	106	99
Accrued compensation	224	205
Asset retirement obligations, current	299	179
Other regulatory liabilities, current	31	16
Over recovered regulatory clause revenues, current	84	10
Other current liabilities	182	154
Total current liabilities	3,476	3,295
Long-Term Debt
Unamortized debt premium (discount), net	(10)	(10)
Unamortized debt issuance expense	(117)	(118)
Long-term Debt	10,225	9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,000	5,627
Deferred credits related to income taxes	121	105
Accumulated deferred investment tax credits	256	204
Employee benefit obligations	703	949
Deferred capacity expense	217	203
Asset retirement obligations, deferred	2,233	1,737
Other deferred credits and liabilities	199	347
Total deferred credits and other liabilities	9,512	8,969
Total Liabilities	23,213	21,880
Redeemable Preferred Stock	45	45
Commitments and Contingent Matters
Common Stockholders' Equity:
Common stock	398	398
Paid-in capital	6,885	6,275
Retained earnings	4,086	4,061
Accumulated other comprehensive loss	(13)	(15)
Common Stockholders' Equity	11,356	10,719
Preference Stock	221	221
Total stockholders' equity	11,356	10,719
Total Liabilities and Stockholders' Equity	34,835	32,865
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	56	74
Receivables --
Customer accounts receivable	72	76
Unbilled revenues	55	54
Under recovered regulatory clause revenues	17	20
Income taxes receivable, current	0	27
Other accounts and notes receivable	6	9
Affiliated	17	1
Accumulated provision for uncollectible accounts	(1)	(1)
Materials and supplies	55	56
Fossil fuel for generation	71	108
Prepaid expenses	18	8
Other regulatory assets, current	44	90
Other current assets	12	14
Total current assets	422	536
Property, Plant, and Equipment:
In service	5,140	5,045
Less accumulated depreciation	1,382	1,296
Plant in service, net of depreciation	3,758	3,749
Other utility plant, net	0	62
Construction work in progress	51	48
Total property, plant, and equipment	3,809	3,859
Deferred Charges and Other Assets:
Deferred charges related to income taxes	58	61
Other regulatory assets, deferred	512	427
Other deferred charges and assets	21	37
Total deferred charges and other assets	591	525
Total Assets	4,822	4,920
Current Liabilities:
Securities due within one year, Other	87	110
Notes payable	268	142
Accounts payable - Affiliated	59	55
Accounts payable - Other	54	44
Customer deposits	35	36
Accrued taxes --
Accrued income taxes	1	4
Other accrued taxes	19	9
Accrued interest	8	9
Accrued compensation	40	36
Liabilities from risk management activities, net of collateral	9	49
Deferred capacity expense, current	22	22
Other regulatory liabilities, current	16	22
Other current liabilities	31	29
Total current liabilities	649	567
Long-Term Debt
Unamortized debt premium (discount), net	(5)	(8)
Unamortized debt issuance expense	(7)	(8)
Long-term Debt	987	1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	948	893
Employee benefit obligations	96	129
Deferred capacity expense	119	141
Asset retirement obligations, deferred	120	113
Other cost of removal obligations	249	233
Other regulatory liabilities, deferred	47	47
Other deferred credits and liabilities	71	102
Total deferred credits and other liabilities	1,650	1,658
Total Liabilities	3,286	3,418
Commitments and Contingent Matters
Common Stockholders' Equity:
Common stock	503	503
Paid-in capital	589	567
Retained earnings	296	285
Accumulated other comprehensive loss	1	0
Common Stockholders' Equity	1,389	1,355
Preference Stock	147	147
Total stockholders' equity	1,389	1,355
Total Liabilities and Stockholders' Equity	4,822	4,920
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	224	98
Receivables --
Customer accounts receivable	29	26
Unbilled revenues	42	36
Income taxes receivable, current	544	20
Other accounts and notes receivable	14	10
Affiliated	15	20
Materials and supplies	76	75
Fossil fuel for generation	100	104
Other regulatory assets, current	115	95
Prepaid income taxes	0	39
Other current assets	8	8
Total current assets	1,167	531
Property, Plant, and Equipment:
In service	4,865	4,886
Less accumulated depreciation	1,289	1,262
Plant in service, net of depreciation	3,576	3,624
Construction work in progress	2,545	2,254
Total property, plant, and equipment	6,121	5,878
Other Property and Investments:
Total other property and investments	12	11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	361	290
Other regulatory assets, deferred	518	525
Income taxes receivable, non-current	0	544
Other deferred charges and assets	56	61
Total deferred charges and other assets	935	1,420
Total Assets	8,235	7,840
Current Liabilities:
Securities due within one year, Parent	551	0
Securities due within one year, Other	629	728
Notes payable	23	500
Accounts payable - Affiliated	62	85
Accounts payable - Other	135	135
Customer deposits	16	16
Accrued taxes --
Accrued income taxes	99	85
Unrecognized tax benefits	383	0
Accrued interest	46	18
Accrued compensation	42	37
Asset retirement obligations, current	32	22
Over recovered regulatory clause liabilities	51	96
Customer liability associated with Kemper refunds	1	73
Other current liabilities	19	41
Total current liabilities	1,538	1,836
Long-Term Debt
Long-term debt affiliated	551	0
Unamortized debt issuance expense	(8)	(8)
Long-term Debt	2,424	1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	756	762
Employee benefit obligations	115	153
Asset retirement obligations, deferred	146	154
Unrecognized tax benefits, deferred	0	368
Other cost of removal obligations	170	165
Other regulatory liabilities, deferred	84	79
Other deferred credits and liabilities	26	45
Total deferred credits and other liabilities	1,297	1,726
Total Liabilities	5,259	5,448
Redeemable Preferred Stock	33	33
Commitments and Contingent Matters
Common Stockholders' Equity:
Common stock	38	38
Paid-in capital	3,525	2,893
Retained earnings	(616)	(566)
Accumulated other comprehensive loss	(4)	(6)
Common Stockholders' Equity	2,943	2,359
Total stockholders' equity	2,943	2,359
Total Liabilities and Stockholders' Equity	8,235	7,840
Southern Power [Member]
Current Assets:
Cash and cash equivalents	1,099	830
Receivables --
Customer accounts receivable	102	75
Other accounts and notes receivable	34	19
Affiliated	57	30
Materials and supplies	337	63
Fossil fuel for generation	15	16
Prepaid income taxes	74	45
Other current assets	39	30
Total current assets	1,757	1,108
Property, Plant, and Equipment:
In service	12,728	7,275
Less accumulated depreciation	1,484	1,248
Plant in service, net of depreciation	11,244	6,027
Construction work in progress	398	1,137
Total property, plant, and equipment	11,642	7,164
Other Property and Investments:
Other intangible assets, net of amortization		317
Intangible assets, net of amortization	436	319
Total other property and investments	436	319
Deferred Charges and Other Assets:
Prepaid long-term service agreements	101	166
Accumulated deferred income taxes – assets	594	0
Other deferred charges and assets -- affiliated	13	9
Other deferred charges and assets	626	139
Total deferred charges and other assets	1,334	314
Total Assets	15,169	8,905
Current Liabilities:
Securities due within one year, Other	560	403
Notes payable	209	137
Accounts payable - Affiliated	88	66
Accounts payable - Other	278	327
Accrued taxes --
Accrued income taxes	148	198
Other accrued taxes	7	5
Accrued interest	36	23
Acquisitions Payable	461	0
Contingent consideration	46	36
Other current liabilities	70	44
Total current liabilities	1,903	1,239
Long-Term Debt
Unamortized debt premium (discount), net	(12)	0
Unamortized debt issuance expense	(29)	(19)
Long-term Debt	5,068	2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	152	601
Accumulated deferred investment tax credits	1,839	889
Accrued income taxes, non-current	0	109
Asset retirement obligations, deferred	64	21
Deferred capacity revenues -- affiliated	17	17
Other deferred credits and liabilities	287	3
Total deferred credits and other liabilities	2,359	1,640
Total Liabilities	9,330	5,598
Redeemable Noncontrolling Interest	164	43
Commitments and Contingent Matters
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	3,671	1,822
Retained earnings	724	657
Accumulated other comprehensive loss	35	4
Common Stockholders' Equity	4,430	2,483
Noncontrolling interests	1,245	781
Total stockholders' equity	5,675	3,264
Total Liabilities and Stockholders' Equity	15,169	8,905
Southern Power [Member] | 1.85% due 2017 [Member]
Long-Term Debt
Senior notes	0	500
Southern Power [Member] | 1.50% due 2018 [Member]
Long-Term Debt
Senior notes	350	350
Southern Power [Member] | Senior Notes Due Two Thousand Nineteen [Member]
Long-Term Debt
Senior notes	600	0
Southern Power [Member] | 2.375% due 2020 [Member]
Long-Term Debt
Senior notes	300	300
Southern Power [Member] | Senior Notes Due Two Thousand Twenty One [Member]
Long-Term Debt
Senior notes	300	0
Southern Power [Member] | Senior Notes Due Two Thousand Twenty Two Through Two Thousand Forty Six [Member]
Long-Term Debt
Senior notes	3,224	1,575
Southern Power [Member] | 1.88% due 2018 [Member]
Long-Term Debt
Other long-term debt	320	0
Southern Power [Member] | Other Long Term Notes Due Two Thousand Thirty Two to Two Thousand Thirty Six [Member]
Long-Term Debt
Other long-term debt	15	13
Successor [Member] | Southern Company Gas [Member]
Current Assets:
Cash and cash equivalents	19
Receivables --
Customer accounts receivable	364
Energy marketing receivable	623
Unbilled revenues	239
Other accounts and notes receivable	76
Accumulated provision for uncollectible accounts	(27)
Materials and supplies	26
Natural gas for sale	631
Prepaid expenses	55
Other regulatory assets, current	81
Prepaid income taxes	24
Assets from risk management activities, net of collateral	128
Other current assets	11
Total current assets	2,250
Property, Plant, and Equipment:
In service	14,508
Less accumulated depreciation	4,439
Plant in service, net of depreciation	10,069
Construction work in progress	496
Total property, plant, and equipment	10,565
Other Property and Investments:
Goodwill	5,967
Equity investments in unconsolidated subsidiaries	1,541
Other intangible assets, net of amortization	366
Miscellaneous property and investments	21
Total other property and investments	7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred	973
Other deferred charges and assets	170
Total deferred charges and other assets	1,143
Total Assets	21,853
Current Liabilities:
Securities due within one year, Other	22
Notes payable	1,257
Energy marketing trade payables	597
Accounts payable	348
Customer deposits	153
Accrued taxes --
Accrued income taxes	26
Other accrued taxes	68
Accrued interest	48
Accrued compensation	58
Liabilities from risk management activities, net of collateral	62
Other regulatory liabilities, current	102
Accrued environmental remediation, current	69
Other current liabilities	108
Total current liabilities	2,918
Long-Term Debt
Unamortized debt premium (discount), net	(9)
Long-term Debt	5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,975
Employee benefit obligations	441
Accrued environmental remediation	357
Other cost of removal obligations	1,616
Other regulatory liabilities, deferred	51
Other deferred credits and liabilities	127
Total deferred credits and other liabilities	4,567
Total Liabilities	12,744
Redeemable Noncontrolling Interests	0
Commitments and Contingent Matters
Common Stockholders' Equity:
Paid-in capital	9,095
Retained earnings	(12)
Accumulated other comprehensive loss	26
Common Stockholders' Equity	9,109
Total stockholders' equity	9,109
Total Liabilities and Stockholders' Equity	21,853
Predecessor [Member] | Southern Company Gas [Member]
Current Assets:
Cash and cash equivalents		19
Receivables --
Customer accounts receivable		316
Energy marketing receivable		445
Unbilled revenues		140
Other accounts and notes receivable		68
Accumulated provision for uncollectible accounts		(29)
Materials and supplies		29
Natural gas for sale		622
Prepaid expenses		67
Other regulatory assets, current		68
Prepaid income taxes		151
Assets from risk management activities, net of collateral		206
Other current assets		13
Total current assets		2,115
Property, Plant, and Equipment:
In service		12,152
Less accumulated depreciation		2,775
Plant in service, net of depreciation		9,377
Construction work in progress		414
Total property, plant, and equipment		9,791
Other Property and Investments:
Goodwill		1,813
Equity investments in unconsolidated subsidiaries		80
Other intangible assets, net of amortization		109
Miscellaneous property and investments		23
Total other property and investments		2,025
Deferred Charges and Other Assets:
Other regulatory assets, deferred		670
Other deferred charges and assets		153
Total deferred charges and other assets		823
Total Assets		14,754
Current Liabilities:
Securities due within one year, Other		545
Notes payable		1,010
Energy marketing trade payables		418
Accounts payable		255
Customer deposits		165
Accrued taxes --
Accrued income taxes		13
Other accrued taxes		46
Accrued interest		49
Accrued compensation		92
Liabilities from risk management activities, net of collateral		44
Other regulatory liabilities, current		134
Accrued environmental remediation, current		67
Other current liabilities		162
Total current liabilities		3,000
Long-Term Debt
Unamortized debt premium (discount), net		(4)
Long-term Debt		3,275
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		1,912
Employee benefit obligations		515
Accrued environmental remediation		364
Other cost of removal obligations		1,538
Other regulatory liabilities, deferred		53
Other deferred credits and liabilities		122
Total deferred credits and other liabilities		4,504
Total Liabilities		10,779
Redeemable Noncontrolling Interests		0
Commitments and Contingent Matters
Common Stockholders' Equity:
Paid-in capital		2,702
Retained earnings		1,421
Accumulated other comprehensive loss		(186)
Common Stockholders' Equity		3,929
Total stockholders' equity		3,975
Total Liabilities and Stockholders' Equity		14,754
Long-Term Debt, Other [Member] | Mississippi Power [Member]
Current Liabilities:
Securities due within one year, Other	$ 78	$ 728

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Amortization expense on other intangible assets	$ 62	$ 12
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	$ 22	$ 12
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%
Southern Power [Member] | 1.50% due 2018 [Member]
Fixed stated interest rate of debt obligation	1.50%	1.50%
Southern Power [Member] | Senior Notes Due Two Thousand Nineteen [Member]
Fixed stated interest rate of debt obligation	1.95%	1.95%
Southern Power [Member] | 2.375% due 2020 [Member]
Fixed stated interest rate of debt obligation	2.375%	2.375%
Southern Power [Member] | Senior Notes Due Two Thousand Twenty One [Member]
Fixed stated interest rate of debt obligation	2.50%	2.50%
Southern Power [Member] | Other Long Term Notes Due Two Thousand eighteen [Member]
Fixed stated interest rate of debt obligation	1.88%	1.88%
Southern Power [Member] | Other Long Term Notes Due Two Thousand Thirty Two to Two Thousand Thirty Six [Member]
Fixed stated interest rate of debt obligation	3.75%	3.75%
Minimum [Member] | Southern Power [Member] | Senior Notes Due Two Thousand Twenty Two Through Two Thousand Forty Six [Member]
Fixed stated interest rate of debt obligation	1.00%	1.00%
Maximum [Member] | Southern Power [Member] | Senior Notes Due Two Thousand Twenty Two Through Two Thousand Forty Six [Member]
Fixed stated interest rate of debt obligation	6.375%	6.375%
Successor [Member] | Southern Company Gas [Member]
Amortization expense on other intangible assets	$ 34
Common stock, par value per share (in dollars per share)	$ 0.01
Common stock, shares authorized	100,000,000
Common stock, shares outstanding	100
Predecessor [Member] | Southern Company Gas [Member]
Amortization expense on other intangible assets		$ 68
Common stock, par value per share (in dollars per share)		$ 5
Common stock, shares authorized		750,000,000
Common stock, shares outstanding		120,400,000

Consolidated Statements of Capi

Consolidated Statements of Capitalization - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Maturity
Long-term debt payable to affiliated trusts —	$ 206,000,000	$ 206,000,000
2,016	0	1,360,000,000
2,017	2,019,000,000	1,995,000,000
2,018	2,353,000,000	1,697,000,000
2,019	3,076,000,000	1,176,000,000
2,020	1,326,000,000	1,327,000,000
2,021	2,655,000,000	200,000,000
2022 through 2051	21,797,000,000	10,972,000,000
Total long -term senior notes and debt	35,247,000,000	20,418,000,000
Pollution control revenue bonds --
Total other long -term debt	9,404,000,000	6,808,000,000
Unamortized Fair Value Adjustment of Long-term Debt	578,000,000	0
Capitalized lease obligations	136,000,000	146,000,000
Unamortized debt premium	52,000,000	61,000,000
Unamortized debt discount	(194,000,000)	(36,000,000)
Unamortized debt issuance expense	(213,000,000)	(241,000,000)
Total long-term debt (annual interest requirement — $1.6 billion)	45,216,000,000	27,362,000,000
Less amount due within one year	2,587,000,000	2,674,000,000
Long-term debt excluding amount due within one year	$ 42,629,000,000	$ 24,688,000,000
Percent capitalization	61.30%	52.60%
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	$ 118,000,000	$ 118,000,000
Total redeemable preferred stock - percent capitalization	0.20%	0.30%
Preferred and preference stock of subsidiaries	$ 1,854,000,000	$ 1,390,000,000
Total preferred and preference stock of subsidiaries - percent capitalization	2.70%	3.00%
Redeemable Noncontrolling Interests	$ 164,000,000	$ 43,000,000
Redeemable Noncontrolling Interest As Percent Of Capitalization	0.20%	0.10%
Common Stockholders' Equity:
Common stock	$ 4,952,000,000	$ 4,572,000,000
Paid-in capital	9,661,000,000	6,282,000,000
Treasury, at cost	(31,000,000)	(142,000,000)
Retained earnings	10,356,000,000	10,010,000,000
Accumulated other comprehensive loss	(180,000,000)	(130,000,000)
Common Stockholders' Equity	$ 24,758,000,000	$ 20,592,000,000
Total common stockholders' equity - percent capitalization	35.60%	44.00%
Total stockholders' equity	$ 26,612,000,000	$ 21,982,000,000
Total Capitalization	$ 69,523,000,000	$ 46,831,000,000
Percent Capitalization	100.00%	100.00%
Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	$ 81,000,000	$ 81,000,000
Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	37,000,000	37,000,000
Noncumulative Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Preferred and preference stock of subsidiaries	45,000,000	45,000,000
Preference Stock, $1 par value [Member]
Redeemable Preferred and Preference Stock:
Preferred and preference stock of subsidiaries	196,000,000	196,000,000
Preference Stock , $100 par or stated value [Member]
Redeemable Preferred and Preference Stock:
Preferred and preference stock of subsidiaries	368,000,000	368,000,000
Redeemable Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	118,000,000	118,000,000
Noncontrolling Interest [Member]
Redeemable Preferred and Preference Stock:
Preferred and preference stock of subsidiaries	1,245,000,000	781,000,000
Adjustable Rate Loans [Member]
Maturity
2,016	0	1,278,000,000
2,017	461,000,000	400,000,000
2,018	1,520,000,000	0
2,021	25,000,000	0
2022 through 2051	15,000,000	13,000,000
Pollution control revenue bonds due 2019 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	25,000,000	25,000,000
Pollution control revenue bonds due 2022 through 2049 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	1,429,000,000	1,509,000,000
Pollution control revenue bonds variable rate, Due 2016 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	0	4,000,000
Pollution control revenue bonds variable rate, Due 2017 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	76,000,000	76,000,000
Pollution control revenue bonds variable rate due 2021 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	65,000,000	65,000,000
Pollution control revenue bonds variable rate, 2022 to 2053 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	1,739,000,000	1,659,000,000
Plant Daniel revenue bonds due 2021 [Member]
Pollution control revenue bonds --
Plant Daniel revenue bonds (7.13%) due 2021	270,000,000	270,000,000
Maturity Of FFB Loans Due 2020 [Member]
Pollution control revenue bonds --
Loan For Federal Financing Bank	44,000,000	37,000,000
Maturity Of FFB Loans Due 2021 [Member]
Pollution control revenue bonds --
Loan For Federal Financing Bank	44,000,000	37,000,000
Maturity Of FFB Bank Loans Due 2022 to 2053 [Member]
Pollution control revenue bonds --
Loan For Federal Financing Bank	2,537,000,000	2,126,000,000
Maturity Of First Mortgage Bonds Due 2019 [Member]
Pollution control revenue bonds --
First Mortgage Bonds	50,000,000	0
First Mortgage Bonds Due Two Thousand Twenty Two To Two Thousand Thirty Eight [Member]
Pollution control revenue bonds --
First Mortgage Bonds	575,000,000	0
Maturity Of Gas Facility Revenue Bonds Due Two Thousand Twenty Two To Two Thousand Thirty Eight [Member]
Pollution control revenue bonds --
Gas Facility Revenue Bonds	200,000,000	0
Maturity of Junior Subordinated Notes Due Two Thousand Seventy Five [Member]
Pollution control revenue bonds --
Junior subordinated notes	2,350,000,000	1,000,000,000
Alabama Power [Member]
Maturity
Long-term debt payable to affiliated trusts —	206,000,000	206,000,000
2,016	0	200,000,000
2,017	525,000,000	525,000,000
2,019	200,000,000	200,000,000
2,020	250,000,000	250,000,000
2,021	220,000,000	200,000,000
2022 through 2051	4,625,000,000	4,225,000,000
Total long-term notes payable	5,845,000,000	5,600,000,000
Pollution control revenue bonds --
Long-term pollution control bonds	1,100,000,000	1,100,000,000
Total other long -term debt	1,096,000,000	1,097,000,000
Capitalized lease obligations	4,000,000	5,000,000
Unamortized debt (discount), net	(9,000,000)	(9,000,000)
Unamortized debt issuance expense	(46,000,000)	(45,000,000)
Total long-term debt (annual interest requirement — $1.6 billion)	7,096,000,000	6,854,000,000
Less amount due within one year	561,000,000	200,000,000
Long-term debt excluding amount due within one year	$ 6,535,000,000	$ 6,654,000,000
Percent capitalization	49.70%	51.40%
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	$ 85,000,000	$ 85,000,000
Total redeemable preferred stock - percent capitalization	0.70%	0.70%
Preferred stock	$ 85,000,000	$ 85,000,000
Preference stock	$ 196,000,000	$ 196,000,000
Total preferred and preference stock of subsidiaries - percent capitalization	1.50%	1.50%
Common Stockholders' Equity:
Common stock	$ 1,222,000,000	$ 1,222,000,000
Paid-in capital	2,613,000,000	2,341,000,000
Retained earnings	2,518,000,000	2,461,000,000
Accumulated other comprehensive loss	(30,000,000)	(32,000,000)
Common Stockholders' Equity	$ 6,323,000,000	$ 5,992,000,000
Total common stockholders' equity - percent capitalization	48.10%	46.40%
Total stockholders' equity	$ 6,323,000,000	$ 5,992,000,000
Total Capitalization	$ 13,139,000,000	$ 12,927,000,000
Percent Capitalization	100.00%	100.00%
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	$ 48,000,000	$ 48,000,000
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Redeemable preferred stock	37,000,000	37,000,000
Alabama Power [Member] | Adjustable Rate Loans [Member]
Maturity
2,021	25,000,000	0
Alabama Power [Member] | Pollution control revenue bonds variable rate, Due 2017 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	36,000,000	36,000,000
Alabama Power [Member] | Pollution control revenue bonds variable rate due 2021 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	65,000,000	65,000,000
Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	207,000,000	287,000,000
Alabama Power [Member] | Pollution Control Revenue Bonds Variable Rate Due 2024 - 2038 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	788,000,000	709,000,000
Georgia Power [Member]
Maturity
2,016	0	250,000,000
2,017	450,000,000	450,000,000
2,018	748,000,000	747,000,000
2,019	500,000,000	502,000,000
2,020	325,000,000	0
2022 through 2051	4,175,000,000	3,850,000,000
Total long-term notes payable	6,198,000,000	6,249,000,000
Pollution control revenue bonds --
Long-term pollution control bonds	1,800,000,000	1,800,000,000
Total other long -term debt	4,445,000,000	4,024,000,000
Capitalized lease obligations	169,000,000	183,000,000
Unamortized debt (discount), net	(10,000,000)	(10,000,000)
Unamortized debt issuance expense	(117,000,000)	(118,000,000)
Total long-term debt (annual interest requirement — $1.6 billion)	10,685,000,000	10,328,000,000
Less amount due within one year	460,000,000	712,000,000
Long-term debt excluding amount due within one year	$ 10,225,000,000	$ 9,616,000,000
Percent capitalization	46.80%	46.70%
Redeemable Preferred and Preference Stock:
Preferred stock	$ 45,000,000	$ 45,000,000
Preference stock	$ 221,000,000	$ 221,000,000
Total preferred and preference stock of subsidiaries - percent capitalization	1.20%	1.30%
Common Stockholders' Equity:
Common stock	$ 398,000,000	$ 398,000,000
Paid-in capital	6,885,000,000	6,275,000,000
Retained earnings	4,086,000,000	4,061,000,000
Accumulated other comprehensive loss	(13,000,000)	(15,000,000)
Common Stockholders' Equity	$ 11,356,000,000	$ 10,719,000,000
Total common stockholders' equity - percent capitalization	52.00%	52.00%
Total stockholders' equity	$ 11,356,000,000	$ 10,719,000,000
Total Capitalization	$ 21,847,000,000	$ 20,601,000,000
Percent Capitalization	100.00%	100.00%
Georgia Power [Member] | Noncumulative Preferred Stock [Member]
Redeemable Preferred and Preference Stock:
Total preferred and preference stock	$ 266,000,000	$ 266,000,000
Georgia Power [Member] | Noncumulative Preferred Stock, $25 par value [Member]
Redeemable Preferred and Preference Stock:
Preferred stock	45,000,000	45,000,000
Georgia Power [Member] | Noncumulative Preferred Stock, $100 par value [Member]
Redeemable Preferred and Preference Stock:
Preference stock	221,000,000	221,000,000
Georgia Power [Member] | Adjustable Rate Loans [Member]
Maturity
2,016	0	450,000,000
Georgia Power [Member] | Pollution control revenue bonds due 2022 through 2049 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	952,000,000	952,000,000
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2016 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	0	4,000,000
Georgia Power [Member] | Pollution control revenue bonds variable rate, 2022 to 2053 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	868,000,000	868,000,000
Georgia Power [Member] | Maturity Of FFB Loans Due 2020 [Member]
Pollution control revenue bonds --
Loan For Federal Financing Bank	44,000,000	37,000,000
Georgia Power [Member] | Maturity Of FFB Loans Due 2021 [Member]
Pollution control revenue bonds --
Loan For Federal Financing Bank	44,000,000	37,000,000
Georgia Power [Member] | Maturity Of FFB Bank Loans Due 2022 to 2053 [Member]
Pollution control revenue bonds --
Loan For Federal Financing Bank	2,537,000,000	2,126,000,000
Gulf Power [Member]
Maturity
2,016	0	110,000,000
2,017	87,000,000	85,000,000
2,018	0
2,019	0
2,020	175,000,000	175,000,000
2,021	0
2022 through 2051	515,000,000	640,000,000
Total long-term notes payable	777,000,000	1,010,000,000
Pollution control revenue bonds --
Long-term pollution control bonds	309,000,000	309,000,000
Total other long -term debt	309,000,000	309,000,000
Unamortized debt (discount), net	(5,000,000)	(8,000,000)
Unamortized debt issuance expense	(7,000,000)	(8,000,000)
Total long-term debt (annual interest requirement — $1.6 billion)	1,074,000,000	1,303,000,000
Less amount due within one year	87,000,000	110,000,000
Long-term debt excluding amount due within one year	$ 987,000,000	$ 1,193,000,000
Percent capitalization	39.10%	44.30%
Redeemable Preferred and Preference Stock:
Total redeemable preferred stock - percent capitalization	5.80%	5.40%
Preference stock	$ 147,000,000	$ 147,000,000
Common Stockholders' Equity:
Common stock	503,000,000	503,000,000
Paid-in capital	589,000,000	567,000,000
Retained earnings	296,000,000	285,000,000
Accumulated other comprehensive loss	1,000,000	0
Common Stockholders' Equity	$ 1,389,000,000	$ 1,355,000,000
Total common stockholders' equity - percent capitalization	55.10%	50.30%
Total stockholders' equity	$ 1,389,000,000	$ 1,355,000,000
Total Capitalization	$ 2,523,000,000	$ 2,695,000,000
Percent Capitalization	100.00%	100.00%
Gulf Power [Member] | 6% Preference stock [Member]
Redeemable Preferred and Preference Stock:
Preference stock	$ 54,000,000	$ 54,000,000
Gulf Power [Member] | 6.45 % Preference stock [Member]
Redeemable Preferred and Preference Stock:
Preference stock	44,000,000	44,000,000
Gulf Power [Member] | 5.6% Preference Stock [Member]
Redeemable Preferred and Preference Stock:
Preference stock	49,000,000	49,000,000
Gulf Power [Member] | Pollution control revenue bonds due 2022 through 2049 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	227,000,000	227,000,000
Gulf Power [Member] | Pollution control revenue bonds variable rate, 2022 to 2053 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	82,000,000	82,000,000
Mississippi Power [Member]
Maturity
2,016	0	300,000,000
2,017	35,000,000	35,000,000
2,019	125,000,000	125,000,000
2022 through 2051	680,000,000	680,000,000
Total long-term notes payable	2,040,000,000	1,565,000,000
Pollution control revenue bonds --
Long-term pollution control bonds	83,000,000	83,000,000
Total other long -term debt	904,000,000	929,000,000
Capitalized lease obligations	74,000,000	77,000,000
Unamortized debt premium	45,000,000	53,000,000
Unamortized debt discount	(2,000,000)	(2,000,000)
Unamortized debt issuance expense	(8,000,000)	(8,000,000)
Total long-term debt (annual interest requirement — $1.6 billion)	3,053,000,000	2,614,000,000
Less amount due within one year	629,000,000	728,000,000
Long-term debt excluding amount due within one year	$ 2,424,000,000	$ 1,886,000,000
Percent capitalization	44.90%	44.10%
Redeemable Preferred and Preference Stock:
Total redeemable preferred stock - percent capitalization	0.60%	0.80%
Preferred stock	$ 33,000,000	$ 33,000,000
Common Stockholders' Equity:
Common stock	38,000,000	38,000,000
Paid-in capital	3,525,000,000	2,893,000,000
Retained earnings	(616,000,000)	(566,000,000)
Accumulated other comprehensive loss	(4,000,000)	(6,000,000)
Common Stockholders' Equity	$ 2,943,000,000	$ 2,359,000,000
Total common stockholders' equity - percent capitalization	54.50%	55.10%
Total stockholders' equity	$ 2,943,000,000	$ 2,359,000,000
Total Capitalization	$ 5,400,000,000	$ 4,278,000,000
Percent Capitalization	100.00%	100.00%
Mississippi Power [Member] | Adjustable Rate Loans [Member]
Maturity
2,016	$ 0	$ 425,000,000
2,018	1,200,000,000	0
Mississippi Power [Member] | Plant Daniel revenue bonds due 2021 [Member]
Pollution control revenue bonds --
Plant Daniel revenue bonds (7.13%) due 2021	270,000,000	270,000,000
Mississippi Power [Member] | Pollution control revenue bonds due 2028 [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	43,000,000	43,000,000
Mississippi Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member]
Pollution control revenue bonds --
Long-term pollution control bonds	40,000,000	40,000,000
Mississippi Power [Member] | Maturity of Long-Term Debt Payable To Parent Company Period One [Member]
Pollution control revenue bonds --
Long-term debt due to parent company	$ 551,000,000	$ 576,000,000

Consolidated Statements of Ca11

Consolidated Statements of Capitalization (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Total long-term debt (annual interest requirement — $)	$ 1,600
Annual dividend requirement	$ 39
Common stock, par value per share (in dollars per share)	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	991,000,000	915,000,000
Treasury shares	800,000	3,400,000
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	2,000,000
Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member]
Dividend Rate, Minimum	5.83%	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]
Dividend Rate, Minimum	5.60%	5.60%
Dividend Rate, Maximum	6.50%	6.50%
Preferred Stock, Par or Stated Value Per Share (in dollars per share)	$ 100	$ 100
Preference stock, shares outstanding	4,000,000	4,000,000
Preference Stock, $1 par value [Member]
Dividend Rate, Minimum	6.45%	6.45%
Dividend Rate, Maximum	6.50%	6.50%
Preferred Stock, Par or Stated Value Per Share (in dollars per share)	$ 1	$ 1
Preference stock, shares authorized	65,000,000	65,000,000
Preference stock, shares outstanding	8,000,000	8,000,000
Redeemable Preferred Stock [Member]
Annual dividend requirement	$ 6	$ 6
Noncumulative Preferred Stock [Member]
Dividend Rate, Minimum	6.00%	6.00%
Dividend Rate, Maximum	6.13%	6.13%
Preferred Stock, Par or Stated Value Per Share (in dollars per share)	$ 25	$ 25
Preference stock, shares authorized	60,000,000	60,000,000
Preference stock, shares outstanding	2,000,000	2,000,000
Maturity of Pollution Control Revenue Bonds 2019 [Member]
Fixed stated interest rate of debt obligation	4.55%	4.55%
Pollution Control Revenue Bonds Due 2016 [Member]
Fixed stated interest rate of debt obligation		0.22%
Pollution Control Revenue Bonds Due 2021 [Member]
Fixed stated interest rate of debt obligation	7.13%	7.13%
Maturity Of First Mortgage Bonds Due 2019 [Member]
Fixed stated interest rate of debt obligation	4.70%
Maturity Of Gas Facility Revenue Bonds Due 2022 to 2033 [Member]
Fixed stated interest rate of debt obligation	1.28%
Affiliate trusts, variable rate, due 2042 [Member]
Fixed stated interest rate of debt obligation	3.95%	3.95%
Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt After Year Five [Member]
Fixed stated interest rate of debt obligation	3.75%	3.75%
Alabama Power [Member]
Total long-term debt (annual interest requirement — $)	$ 290
Annual dividend requirement	$ 13
Common stock, par value per share (in dollars per share)	$ 40	$ 40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value [Member]
Dividend Rate, Minimum	5.83%	5.83%
Preferred Stock, Par or Stated Value Per Share (in dollars per share)	$ 1	$ 1
Redeemable Cumulative preferred stock, shares authorized	27,500,000	27,500,000
Redeemable Cumulative preferred stock, shares outstanding	1,520,000	1,520,000
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]
Dividend Rate, Minimum	6.45%	6.45%
Dividend Rate, Maximum	6.50%	6.50%
Preferred Stock, Par or Stated Value Per Share (in dollars per share)	$ 1	$ 1
Alabama Power [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	8,000,000
Alabama Power [Member] | Affiliate trusts, variable rate, due 2042 [Member]
Fixed stated interest rate of debt obligation	3.95%	3.95%
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		5.20%
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [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 Four [Member]
Fixed stated interest rate of debt obligation	3.375%	3.375%
Georgia Power [Member]
Total long-term debt (annual interest requirement — $)	$ 402
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] | Pollution control revenue bonds variable rate, Due 2016 [Member]
Fixed stated interest rate of debt obligation		0.22%
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		3.00%
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [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 Three [Member]
Fixed stated interest rate of debt obligation	4.25%	4.25%
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	2.40%	2.40%
Gulf Power [Member]
Total long-term debt (annual interest requirement — $)	$ 42
Annual dividend requirement	$ 9
Common stock, shares authorized	20,000,000	20,000,000
Preference stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	5,642,717	5,642,717
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] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		5.30%
Gulf Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Four [Member]
Fixed stated interest rate of debt obligation	4.75%	4.75%
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]
Total long-term debt (annual interest requirement — $)	$ 102
Dividend Rate, Minimum	4.40%	4.40%
Dividend Rate, Maximum	5.25%	5.25%
Preferred Stock, Par or Stated Value Per Share (in dollars per share)	$ 100	$ 100
Redeemable Cumulative preferred stock, shares authorized	1,244,139	1,244,139
Redeemable Cumulative preferred stock, shares outstanding	334,210	334,210
Annual dividend requirement	$ 2
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Mississippi Power [Member] | 2028 [Member]
Fixed stated interest rate of debt obligation	5.15%	5.15%
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 Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		2.35%
Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [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 Three [Member]
Fixed stated interest rate of debt obligation	5.55%	5.55%
Mississippi Power [Member] | Maturity of Long-Term Debt Payable to Parent Company [Member]
Fixed stated interest rate of debt obligation	2.27%	2.27%
Minimum [Member] | Maturity of Pollution Control Revenue Bonds 2022 through 2049 [Member]
Fixed stated interest rate of debt obligation	0.65%	0.65%
Minimum [Member] | Pollution Control Revenue Bonds Due 2017 [Member]
Fixed stated interest rate of debt obligation	0.77%	0.77%
Minimum [Member] | Pollution Control Revenue Bonds Due 2022 to 2053 [Member]
Fixed stated interest rate of debt obligation	0.75%	0.75%
Minimum [Member] | Pollution Control Revenue Bonds Due 2021 [Member]
Fixed stated interest rate of debt obligation	0.82%	0.82%
Minimum [Member] | FFB Loans Due 2022 to 2044 [Member]
Fixed stated interest rate of debt obligation	2.57%	2.57%
Minimum [Member] | First Mortgage Bonds Due 2023 to 2033 [Member]
Fixed stated interest rate of debt obligation	2.66%
Minimum [Member] | Junior Subordinated Notes Due 2076 [Member]
Fixed stated interest rate of debt obligation	5.25%	5.25%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt After Year Five [Member]
Fixed stated interest rate of debt obligation	1.00%	1.00%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		1.95%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [Member]
Fixed stated interest rate of debt obligation	1.30%	1.30%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Fixed stated interest rate of debt obligation	1.50%	1.50%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member]
Fixed stated interest rate of debt obligation	1.85%	1.85%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt in Year Four [Member]
Fixed stated interest rate of debt obligation	2.38%	2.38%
Minimum [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	2.35%	2.35%
Minimum [Member] | Maturity Of FFB Loans Due 2020 [Member]
Fixed stated interest rate of debt obligation	2.57%	2.57%
Minimum [Member] | Maturity Of FFB Loans Due 2021 [Member]
Fixed stated interest rate of debt obligation	2.57%	2.57%
Minimum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		0.76%
Minimum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [Member]
Fixed stated interest rate of debt obligation	1.82%	1.82%
Minimum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Fixed stated interest rate of debt obligation	1.88%
Minimum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	1.87%
Minimum [Member] | Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Two to Two Thousand Forty Six [Member]
Fixed stated interest rate of debt obligation	2.80%	2.80%
Minimum [Member] | Alabama Power [Member] | Maturity of Long Term Senior Notes And Debt Two Thousand Seventeen [Member]
Fixed stated interest rate of debt obligation	5.50%	5.50%
Minimum [Member] | Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member]
Fixed stated interest rate of debt obligation	0.65%	0.65%
Minimum [Member] | Alabama Power [Member] | Pollution control revenue bonds due 2024-2038 [Member]
Fixed stated interest rate of debt obligation	0.77%	0.77%
Minimum [Member] | Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member]
Fixed stated interest rate of debt obligation	0.77%	0.77%
Minimum [Member] | Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Twenty One [Member]
Fixed stated interest rate of debt obligation	0.82%	0.82%
Minimum [Member] | Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	3.95%	3.95%
Minimum [Member] | Alabama Power [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	1.87%	1.87%
Minimum [Member] | Georgia Power [Member] | FFB Loans Due 2022 to 2044 [Member]
Fixed stated interest rate of debt obligation	2.57%	2.57%
Minimum [Member] | Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Two to Two Thousand Forty Three [Member]
Fixed stated interest rate of debt obligation	2.85%	2.85%
Minimum [Member] | Georgia Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member]
Fixed stated interest rate of debt obligation		0.76%
Minimum [Member] | Georgia Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member]
Fixed stated interest rate of debt obligation	1.38%	1.38%
Minimum [Member] | Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Fixed stated interest rate of debt obligation	1.95%	1.95%
Minimum [Member] | Georgia Power [Member] | Variable rate, Due 2022-2053 [Member]
Fixed stated interest rate of debt obligation	0.77%	0.77%
Minimum [Member] | Georgia Power [Member] | Maturity Of FFB Loans Due 2020 [Member]
Fixed stated interest rate of debt obligation	2.57%	2.57%
Minimum [Member] | Georgia Power [Member] | Maturity Of FFB Loans Due 2021 [Member]
Fixed stated interest rate of debt obligation	2.57%	2.57%
Minimum [Member] | Gulf Power [Member] | 2020-2051 [Member]
Fixed stated interest rate of debt obligation	3.10%	3.10%
Minimum [Member] | Gulf Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member]
Fixed stated interest rate of debt obligation	1.15%	1.15%
Minimum [Member] | Gulf Power [Member] | Pollution control revenue bonds due 2022-2042 [Member]
Fixed stated interest rate of debt obligation	0.75%	0.75%
Minimum [Member] | Gulf Power [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [Member]
Fixed stated interest rate of debt obligation	2.93%	2.93%
Minimum [Member] | Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Thirty Five Thousand Forty Two [Member]
Fixed stated interest rate of debt obligation	1.63%	1.63%
Minimum [Member] | Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member]
Fixed stated interest rate of debt obligation		1.84%
Minimum [Member] | Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Eighteen [Member]
Fixed stated interest rate of debt obligation	2.15%	2.15%
Minimum [Member] | Mississippi Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member]
Fixed stated interest rate of debt obligation	0.83%	0.83%
Maximum [Member] | Maturity of Pollution Control Revenue Bonds 2022 through 2049 [Member]
Fixed stated interest rate of debt obligation	5.15%	5.15%
Maximum [Member] | Pollution Control Revenue Bonds Due 2017 [Member]
Fixed stated interest rate of debt obligation	0.87%	0.87%
Maximum [Member] | Pollution Control Revenue Bonds Due 2022 to 2053 [Member]
Fixed stated interest rate of debt obligation	0.87%	0.87%
Maximum [Member] | Pollution Control Revenue Bonds Due 2021 [Member]
Fixed stated interest rate of debt obligation	0.86%	0.86%
Maximum [Member] | FFB Loans Due 2022 to 2044 [Member]
Fixed stated interest rate of debt obligation	3.86%	3.86%
Maximum [Member] | First Mortgage Bonds Due 2023 to 2033 [Member]
Fixed stated interest rate of debt obligation	6.58%
Maximum [Member] | Junior Subordinated Notes Due 2076 [Member]
Fixed stated interest rate of debt obligation	6.25%	6.25%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt After Year Five [Member]
Fixed stated interest rate of debt obligation	8.70%	8.70%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		5.30%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [Member]
Fixed stated interest rate of debt obligation	7.20%	7.20%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Fixed stated interest rate of debt obligation	5.40%	5.40%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member]
Fixed stated interest rate of debt obligation	5.55%	5.55%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt in Year Four [Member]
Fixed stated interest rate of debt obligation	4.75%	4.75%
Maximum [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	9.10%	9.10%
Maximum [Member] | Maturity Of FFB Loans Due 2020 [Member]
Fixed stated interest rate of debt obligation	3.86%	3.86%
Maximum [Member] | Maturity Of FFB Loans Due 2021 [Member]
Fixed stated interest rate of debt obligation	3.86%	3.86%
Maximum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt In Last Twelve Months [Member]
Fixed stated interest rate of debt obligation		3.50%
Maximum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [Member]
Fixed stated interest rate of debt obligation	3.75%	3.75%
Maximum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Fixed stated interest rate of debt obligation	2.24%
Maximum [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	2.10%
Maximum [Member] | Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Two to Two Thousand Forty Six [Member]
Fixed stated interest rate of debt obligation	6.125%	6.125%
Maximum [Member] | Alabama Power [Member] | Maturity of Long Term Senior Notes And Debt Two Thousand Seventeen [Member]
Fixed stated interest rate of debt obligation	5.55%	5.55%
Maximum [Member] | Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member]
Fixed stated interest rate of debt obligation	1.65%	1.65%
Maximum [Member] | Alabama Power [Member] | Pollution control revenue bonds due 2024-2038 [Member]
Fixed stated interest rate of debt obligation	0.82%	0.82%
Maximum [Member] | Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member]
Fixed stated interest rate of debt obligation	0.79%	0.79%
Maximum [Member] | Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Twenty One [Member]
Fixed stated interest rate of debt obligation	0.86%	0.86%
Maximum [Member] | Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	2.38%	2.38%
Maximum [Member] | Alabama Power [Member] | Adjustable Rate Loans [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member]
Fixed stated interest rate of debt obligation	2.10%	2.10%
Maximum [Member] | Georgia Power [Member] | FFB Loans Due 2022 to 2044 [Member]
Fixed stated interest rate of debt obligation	3.86%	3.86%
Maximum [Member] | Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Two to Two Thousand Forty Three [Member]
Fixed stated interest rate of debt obligation	5.95%	5.95%
Maximum [Member] | Georgia Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member]
Fixed stated interest rate of debt obligation		0.83%
Maximum [Member] | Georgia Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member]
Fixed stated interest rate of debt obligation	4.00%	4.00%
Maximum [Member] | Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Fixed stated interest rate of debt obligation	5.40%	5.40%
Maximum [Member] | Georgia Power [Member] | Variable rate, Due 2022-2053 [Member]
Fixed stated interest rate of debt obligation	0.87%	0.87%
Maximum [Member] | Georgia Power [Member] | Maturity Of FFB Loans Due 2020 [Member]
Fixed stated interest rate of debt obligation	3.86%	3.86%
Maximum [Member] | Georgia Power [Member] | Maturity Of FFB Loans Due 2021 [Member]
Fixed stated interest rate of debt obligation	3.86%	3.86%
Maximum [Member] | Gulf Power [Member] | 2020-2051 [Member]
Fixed stated interest rate of debt obligation	5.75%	5.75%
Maximum [Member] | Gulf Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member]
Fixed stated interest rate of debt obligation	4.45%	4.45%
Maximum [Member] | Gulf Power [Member] | Pollution control revenue bonds due 2022-2042 [Member]
Fixed stated interest rate of debt obligation	0.84%	0.84%
Maximum [Member] | Gulf Power [Member] | Maturity of Long Term Senior Notes and Debt In Next Twelve Months [Member]
Fixed stated interest rate of debt obligation	5.90%	5.90%
Maximum [Member] | Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Thirty Five Thousand Forty Two [Member]
Fixed stated interest rate of debt obligation	5.40%	5.40%
Maximum [Member] | Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member]
Fixed stated interest rate of debt obligation		1.90%
Maximum [Member] | Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Eighteen [Member]
Fixed stated interest rate of debt obligation	2.24%	2.24%
Maximum [Member] | Mississippi Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member]
Fixed stated interest rate of debt obligation	0.87%	0.87%

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Noncontrolling Interest [Member]	Treasury Stock [Member]	Paid In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Preferred And Preference Stock [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]Accumulated Other Comprehensive Income (Loss) [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]Accumulated Other Comprehensive Income (Loss) [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]Accumulated Other Comprehensive Income (Loss) [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]Accumulated Other Comprehensive Income (Loss) [Member]	Southern Power [Member]	Southern Power [Member]Common Stock [Member]	Southern Power [Member]Noncontrolling Interest [Member]	Southern Power [Member]Common Stockholder's Equity Not Including Noncontrolling Interest [Member]	Southern Power [Member]Paid In Capital [Member]	Southern Power [Member]Retained Earnings [Member]	Southern Power [Member]Accumulated Other Comprehensive Income (Loss) [Member]	Southern Company Gas [Member]	Southern Company Gas [Member]Common Stock [Member]	Southern Company Gas [Member]Noncontrolling Interest [Member]	Southern Company Gas [Member]Treasury Stock [Member]	Southern Company Gas [Member]Paid In Capital [Member]	Southern Company Gas [Member]Retained Earnings [Member]	Southern Company Gas [Member]Accumulated Other Comprehensive Income (Loss) [Member]
Beginning Balance, Shares (Predecessor [Member]) at Dec. 31, 2013																																					118,889		217
Beginning Balance, Shares at Dec. 31, 2013		892,733		5,647						31,000					9,000					5,000					1,000					0
Beginning Balance (Predecessor [Member]) at Dec. 31, 2013																																				$ 3,613	$ 595	$ 45	$ (8)	$ 2,054	$ 1,063	$ (136)
Beginning Balance at Dec. 31, 2013	$ 19,764	$ 4,461	$ 0	$ (250)	$ 5,362	$ 9,510	$ (75)	$ 756	$ 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	$ 0	$ 1,564	$ 1,029	$ 532	$ 3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income | Predecessor [Member]																																				482					482
Net income	1,963					1,963			761			761		1,225			1,225		140			140		(329)			(329)
Net income attributable to Southern Power Company																													172			172		172
Other comprehensive income (loss) | Predecessor [Member]																																				(72)		(2)				(70)
Other comprehensive income (loss)	(53)						(53)		(3)				(3)	(3)				(3)						1				1
Stock issued, shares | Predecessor [Member]																																					236
Stock issued, shares		15,769		4,996																0
Stock issued | Predecessor [Member]																																				12	$ 1			11
Stock issued	806	$ 78		$ 227	501			0											50	$ 50
Share-based compensation, shares | Predecessor [Member]																																					522
Stock-based compensation | Predecessor [Member]																																				25	$ 3			22
Stock-based compensation	86				86
Capital contributions from parent company									42		42			563		563			7		7			235		235			147			147	147
Cash dividends on common stock | Predecessor [Member]																																				(233)					(233)
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
Distributions to noncontrolling interests | Predecessor [Member]																																				(17)		(17)
Net income (loss) attributable to noncontrolling interests | Predecessor [Member]																																				18		18
Net income (loss) attributable to noncontrolling interests	(2)		(2)																										(2)		(2)
Other, shares				(74)
Other	7		2	$ (3)	6	2								(1)			(1)
Ending Balance, Shares (Predecessor [Member]) at Dec. 31, 2014																																					119,647		217
Ending Balance, Shares at Dec. 31, 2014		908,502		725						31,000					9,000					5,000					1,000					0
Ending Balance (Predecessor [Member]) at Dec. 31, 2014																																				3,828	$ 599	44	$ (8)	2,087	1,312	(206)
Ending Balance at Dec. 31, 2014	20,926	$ 4,539	221	$ (26)	5,955	9,609	(128)	756	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	219	1,752	1,176	573	3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income | Predecessor [Member]																																				353					353
Net income	2,367					2,367			785			785		1,260			1,260		148			148		(8)			(8)
Net income attributable to Southern Power Company																													215			215		215
Other comprehensive income (loss) | Predecessor [Member]																																				20						20
Other comprehensive income (loss)	(2)						(2)		(3)				(3)	(7)				(7)	1				1	1				1	1			1			1
Stock issued, shares | Predecessor [Member]																																					221
Stock issued, shares		6,571		(2,599)																1,000
Stock issued | Predecessor [Member]																																				12	$ 1			11
Stock issued	256	$ 33		$ 0	223														20	$ 20	0
Share-based compensation, shares | Predecessor [Member]																																					509
Stock-based compensation | Predecessor [Member]																																				4	$ 3			1
Stock-based compensation	100				100
Stock repurchased, at cost	(115)			$ (115)
Capital contributions from parent company									37		37			79		79			7		7			281		281			646			646	646
Cash dividends on common stock | Predecessor [Member]																																				(244)					(244)
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 | Predecessor [Member]																																				(18)		(18)
Distributions to noncontrolling interests	(18)		(18)																										(17)		(17)
Net income (loss) attributable to noncontrolling interests | Predecessor [Member]																																				20		20
Net income (loss) attributable to noncontrolling interests	12		12																										12		12
Other, shares				(28)
Other	(2)		(1)	$ (1)	4	(7)		3	(8)			(8)												1			1
Ending Balance, Shares (Predecessor [Member]) at Dec. 31, 2015																																					120,377		217
Ending Balance, Shares at Dec. 31, 2015		915,073		3,352						31,000					9,000					6,000					1,000					0
Ending Balance (Predecessor [Member]) at Dec. 31, 2015																																				3,975	$ 603	46	$ (8)	2,099	1,421	(186)
Ending Balance at Dec. 31, 2015	21,982	$ 4,572	781	$ (142)	6,282	10,010	(130)	609	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	781	2,483	1,822	657	4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income | Predecessor [Member]																																				131					131
Other comprehensive income (loss) | Predecessor [Member]																																				(35)						(35)
Stock issued, shares | Predecessor [Member]																																					95
Stock issued | Predecessor [Member]																																				6				6
Share-based compensation, shares | Predecessor [Member]																																					270
Stock-based compensation | Predecessor [Member]																																				30	$ 2			28
Cash dividends on common stock | Predecessor [Member]																																				(128)					(128)
Ending Balance, Shares (Predecessor [Member]) at Jun. 30, 2016																																					120,742		217
Ending Balance (Successor [Member]) at Jun. 30, 2016																																				8,001				8,001
Ending Balance (Predecessor [Member]) at Jun. 30, 2016																																				3,933	$ 605	0	$ (8)	2,133	1,424	(221)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling Interest, Decrease from Reclassification to Temporary Equity | Predecessor [Member]																																				(46)		(46)
Beginning Balance, Shares (Predecessor [Member]) at Dec. 31, 2015																																					120,377		217
Beginning Balance, Shares at Dec. 31, 2015		915,073		3,352						31,000					9,000					6,000					1,000					0
Beginning Balance (Predecessor [Member]) at Dec. 31, 2015																																				3,975	$ 603	46	$ (8)	2,099	1,421	(186)
Beginning Balance at Dec. 31, 2015	21,982	$ 4,572	781	$ (142)	6,282	10,010	(130)	609	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	781	2,483	1,822	657	4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,448					2,448			822			822		1,330			1,330		131			131		(50)			(50)
Net income attributable to Southern Power Company																													338			338		338
Other comprehensive income (loss)	(50)						(50)		2				2	2				2	1				1	2				2	31			31			31
Stock issued, shares		76,140		2,599
Stock issued	3,758	$ 380		$ 115	3,263
Stock-based compensation	120				120
Capital contributions from parent company									272		272			610		610			22		22			632		632			1,850			1,850	1,850
Cash dividends on common stock	(2,104)					(2,104)			(765)			(765)		(1,305)			(1,305)		(120)			(120)							(272)			(272)		(272)
Contributions from noncontrolling interests	618		618																										618		618
Distributions to noncontrolling interests	(57)		(57)																										(57)		(57)
Purchase of membership interests from noncontrolling interests	(129)		(129)																										(129)		(129)
Net income (loss) attributable to noncontrolling interests	32		32																										32		32
Other, shares				(66)
Other	(6)		0	$ (4)	(4)	2		0																					0				(1)	1
Ending Balance, Shares (Successor [Member]) at Dec. 31, 2016																																					0		0
Ending Balance, Shares at Dec. 31, 2016		991,213		819						31,000					9,000					6,000					1,000					0
Ending Balance (Successor [Member]) at Dec. 31, 2016																																				9,109	$ 0	0	$ 0	9,095	(12)	26
Ending Balance at Dec. 31, 2016	26,612	$ 4,952	1,245	$ (31)	9,661	10,356	(180)	609	6,323	$ 1,222	2,613	2,518	(30)	11,356	$ 398	6,885	4,086	(13)	1,389	$ 503	589	296	1	2,943	$ 38	3,525	(616)	(4)	5,675	$ 0	1,245	4,430	3,671	724	35
Beginning Balance, Shares (Predecessor [Member]) at Jun. 30, 2016																																					120,742		217
Beginning Balance (Successor [Member]) at Jun. 30, 2016																																				8,001				8,001
Beginning Balance (Predecessor [Member]) at Jun. 30, 2016																																				3,933	$ 605	0	$ (8)	2,133	1,424	(221)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income | Successor [Member]																																				114					114
Other comprehensive income (loss) | Successor [Member]																																				26						26
Stock-based compensation | Successor [Member]																																				9				9
Capital contributions from parent company | Successor [Member]																																				1,085				1,085
Cash dividends on common stock | Successor [Member]																																				(126)					(126)
Ending Balance, Shares (Successor [Member]) at Dec. 31, 2016																																					0		0
Ending Balance, Shares at Dec. 31, 2016		991,213		819						31,000					9,000					6,000					1,000					0
Ending Balance (Successor [Member]) at Dec. 31, 2016																																				$ 9,109	$ 0	$ 0	$ 0	$ 9,095	$ (12)	$ 26
Ending Balance at Dec. 31, 2016	$ 26,612	$ 4,952	$ 1,245	$ (31)	$ 9,661	$ 10,356	$ (180)	$ 609	$ 6,323	$ 1,222	$ 2,613	$ 2,518	$ (30)	$ 11,356	$ 398	$ 6,885	$ 4,086	$ (13)	$ 1,389	$ 503	$ 589	$ 296	$ 1	$ 2,943	$ 38	$ 3,525	$ (616)	$ (4)	$ 5,675	$ 0	$ 1,245	$ 4,430	$ 3,671	$ 724	$ 35

Consolidated Statements of St13

Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Cash dividends (in dollars per share)	$ 0.5600	$ 0.5600	$ 0.5600	$ 0.5425	$ 0.5425	$ 0.5425	$ 0.5425	$ 0.525	$ 2.2225	$ 2.1525	$ 2.0825

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies [Line Items]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows. In 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. 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 In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, Southern Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. Southern Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on Southern Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5, 8, and 14 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Southern Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. Southern Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of Southern Company. Regulatory Assets and Liabilities The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans $ 3,959 $ 3,440 (a,n) Deferred income tax charges 1,590 1,514 (b) Asset retirement obligations-asset 1,080 481 (b,n) Environmental remediation-asset 491 78 (j,n) Other regulatory assets 355 299 (k) Remaining net book value of retired assets 351 283 (o) Under recovered regulatory clause revenues 273 142 (g) Loss on reacquired debt 243 248 (c) Property damage reserves-asset 206 92 (i) Kemper IGCC 201 216 (h) Vacation pay 182 178 (f,n) Long-term debt fair value adjustment 155 — (p) Deferred PPA charges 141 163 (e,n) Nuclear outage 97 88 (g) Fuel-hedging-asset 35 225 (d,n) Other cost of removal obligations (2,774 ) (1,177 ) (b) Deferred income tax credits (219 ) (187 ) (b) Over recovered regulatory clause revenues (203 ) (261 ) (g) Property damage reserves-liability (177 ) (178 ) (l) Other regulatory liabilities (110 ) (35 ) (m) Asset retirement obligations-liability (10 ) (45 ) (b,n) Total regulatory assets (liabilities), net $ 5,866 $ 5,564 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years . (d) 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 fuel and energy cost recovery mechanisms. (e) Recovered over the life of the PPA for periods up to seven years . (f) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding ten years . (h) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two , seven , or 10 years . For additional information, see Note 3 under " Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities ." (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years . (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 4 years . (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 11 years . (p) Recorded in relation to the Merger. Recovered over the remaining life of the original debt issuances, which range up to 22 years . For additional information see Note 12 under " Southern Company – Merger with Southern Company Gas ." In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under " Regulatory Matters – Alabama Power ," " Regulatory Matters – Georgia Power ," " Regulatory Matters – Gulf Power ," " Regulatory Matters – Southern Company Gas ," 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. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. 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 and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Income and Other Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2016 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2016 tax year along with various state NOL carryforwards, which could result in income tax benefits in the future, if utilized. See Note 5 under " Current and Deferred Income Taxes – Tax Credit Carryforwards " and " – Net Operating Loss " for additional information. Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under " Unrecognized Tax Benefits " for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Electric utilities: Generation $ 48,836 $ 41,648 Transmission 11,156 10,544 Distribution 18,418 17,670 General 4,629 4,377 Plant acquisition adjustment 126 123 Electric utility plant in service 83,165 74,362 Natural gas distribution utilities: Transportation and distribution 11,996 — Utility plant in service 95,161 74,362 Information technology equipment and software 544 222 Communications equipment 424 418 Storage facilities 1,463 — Other 824 116 Total other plant in service 3,255 756 Total plant in service $ 98,416 $ 75,118 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, 2016 2015 (in millions) Office building $ 61 $ 61 Nitrogen plant 83 83 Computer-related equipment 63 61 Gas pipeline 6 6 Less: Accumulated amortization (69 ) (59 ) Balance, net of amortization $ 144 $ 152 The amount of non-cash property additions recognized for the years ended December 31, 2016 , 2015 , and 2014 was $1.5 billion , $844 million , and $528 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, 2016 , 2015 , and 2014 was $18 million , $13 million , and $25 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 2016 and 2015 and 3.1% in 2014 . Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $29.3 billion and $23.7 billion at December 31, 2016 and 2015 , 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. Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million in each of 2014, 2015, and 2016 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under " Regulatory Matters – Gulf Power – Retail Base Rate Cases " for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 65 years . Accumulated depreciation for other plant in service totaled $550 million and $510 million at December 31, 2016 and 2015 , respectively. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See " Nuclear Decommissioning " herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 3,759 $ 2,201 Liabilities incurred 66 662 Liabilities settled (171 ) (37 ) Accretion 162 115 Cash flow revisions 698 818 Balance at end of year $ 4,514 $ 3,759 The increases in cash flow revisions and liabilities incurred in 2016 primarily relate to changes in ash pond closure strategy. The cash flow revisions in 2015 are primarily related 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, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, 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 with respect to compliance activities, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates. 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, 2016 and 2015 , approximately $56 million and $76 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 $58 million and $78 million at December 31, 2016 and 2015 , 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, 2016 , investment securities in the Funds totaled $1.6 billion , consisting of equity securities of $878 million , debt securities of $685 million , and $41 million of other securities. 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. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investm
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 the Company and three other traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary. The Company is subject to regulation by the FERC and the Alabama PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 12 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. 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 $460 million , $438 million , and $400 million during 2016 , 2015 , and 2014 , 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 $249 million , $243 million , and $234 million during 2016 , 2015 , and 2014 , respectively. The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which totaled $13 million in 2016 , $11 million in 2015 , and $13 million in 2014 . Mississippi Power also reimbursed the Company for any direct fuel purchases delivered from one of the Company's transfer facilities. There were no fuel purchases in 2016. Fuel purchases were $8 million and $34 million in 2015 and 2014 , respectively. See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. Under a related tariff, the Company received $12 million in 2016, $14 million in 2015, and $12 million in 2014 and expects to recover a total of approximately $73 million from 2017 through 2023 from Gulf Power. On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016, transportation costs under this agreement were approximately $2 million . The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional electric operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans $ 947 $ 903 (i,j) Deferred income tax charges 526 522 (a,k) Under/(over) recovered regulatory clause revenues 76 (97 ) (d) Nuclear outage 70 53 (d) Remaining net book value of retired assets 69 76 (l) Vacation pay 69 66 (c,j) Loss on reacquired debt 68 75 (b) Other regulatory assets 50 53 (f) Asset retirement obligations 12 (40 ) (a) Fuel-hedging losses 1 55 (e,j) Other cost of removal obligations (684 ) (722 ) (a) Natural disaster reserve (69 ) (75 ) (h) Deferred income tax credits (65 ) (70 ) (a) Other regulatory liabilities (23 ) (8 ) (e,g) Total regulatory assets (liabilities), net $ 1,047 $ 791 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 other cost of removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years . (c) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years . See Note 3 under "Retail Regulatory Matters" for additional information. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years . Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (f) Comprised of components including generation site selection/evaluation costs, PPA capacity (to be recovered over the next 12 months ), and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. (g) Comprised of components including mine reclamation and remediation liabilities and fuel-hedging gains. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. (h) Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. (i) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Included in the deferred income tax charges are $16 million for 2016 and $17 million for 2015 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 and the Alabama PSC continuously monitor the under/over recovered balances. The Company files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP Compliance" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 13,551 $ 12,820 Transmission 3,921 3,773 Distribution 6,707 6,432 General 1,840 1,713 Plant acquisition adjustment 12 12 Total plant in service $ 26,031 $ 24,750 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. Nuclear Outage Accounting Order In accordance with an Alabama PSC order, nuclear outage operations and maintenance expenses for the two units at Plant Farley are deferred to a regulatory asset when the charges actually occur and are then amortized over a subsequent 18 -month period with the fall outage costs amortization beginning in January of the following year and the spring outage costs amortization beginning in July of the same year. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2016 , 2.9% in 2015 , and 3.3% in 2014 . Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. In 2016, the Company submitted an updated depreciation study to the FERC and received authorization to use the recommended rates beginning January 2017. The study was also provided to the Alabama PSC. The revised rates will not have a significant impact on depreciation expense in 2017. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 1,448 $ 829 Liabilities incurred 5 402 Liabilities settled (25 ) (3 ) Accretion 73 53 Cash flow revisions 32 167 Balance at end of year $ 1,533 $ 1,448 The increase in liabilities incurred and cash flow revisions in 2016 and 2015 are primarily related to changes in ash pond closure strategy. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2016 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 with respect to compliance activities, 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. 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, 2016 , investment securities in the Funds totaled $790 million , consisting of equity securities of $552 million , debt securities of $208 million , and $30 million of other securities. 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. 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 $351 million , $438 million , and $244 million in 2016 , 2015 , and 2014 , respectively, all of which were reinvested. For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $76 million , which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million , which included $57 million related to unrealized losses on securities held in the Funds at December 31, 2015 . 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 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, the accumulated provisions for decommissioning were as follows: 2016 2015 (in millions) External trust funds $ 790 $ 734 Internal reserves 19 20 Total $ 809 $ 754 Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2016 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 The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.4% in 2016 , 8.7% in 2015 , and 8.8% in 2014 . AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 4.2% in 2016 , 9.3% in 2015 , and 7.9% in 2014 . 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 impairm
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 electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The equity method is used for subsidiaries in which the Company has significant influence but does not control. The Company is subject to regulation by the FERC and the Georgia PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. In 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. 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 In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it is expected to have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 12 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. 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 $606 million , $585 million , and $555 million in 2016 , 2015 , and 2014 , 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, operations, and construction management. Costs for these services amounted to $666 million , $681 million , and $643 million in 2016 , 2015 , and 2014 , respectively. The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $265 million , $179 million , and $144 million in 2016 , 2015 , and 2014 , respectively. 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 $8 million , $12 million , and $9 million in 2016 , 2015 , and 2014 , respectively. See Note 4 for additional information. In 2014, prior to Southern Company's acquisition of PowerSecure on May 9, 2016, the Company entered into agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. On October 4, 2016, the two facilities began commercial operation. Payments of approximately $118 million made by the Company to PowerSecure under the agreements since 2014 are included in utility plant in service at December 31, 2016 . On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016 , transportation costs under this agreement were approximately $35 million . Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016 , natural gas purchases made by the Company from Southern Company Gas' subsidiaries were approximately $10 million . The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . The traditional electric operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans $ 1,348 $ 1,307 (a, j) Deferred income tax charges 681 683 (b, j) Loss on reacquired debt 137 150 (c, j) Asset retirement obligations 893 411 (b, j) Vacation pay 91 91 (d, j) Cancelled construction projects 44 56 (e) Remaining net book value of retired assets 166 171 (f) Storm damage reserves 206 92 (g) Other regulatory assets 97 110 (h) Other cost of removal obligations 3 (31 ) (b) Deferred income tax credits (121 ) (105 ) (b, j) Other regulatory liabilities (39 ) (2 ) (i, j) Total regulatory assets (liabilities), net $ 3,506 $ 2,933 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 13 years . See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $26 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022. (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 36 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. The net book value of Plant Mitchell Unit 3 at December 31, 2016 was $12 million , which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $5 million , and $31 million related to obsolete inventories of certain retired units will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information. (g) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (h) Comprised of several components including deferred nuclear outages, environmental remediation, building lease, and demand-side management tariff under-recovery. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months . The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $46 million at December 31, 2016 will be determined by the Georgia PSC in the 2019 base rate case. (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. 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. The Company had $83 million in federal ITCs at December 31, 2016 that will expire by 2036. State ITCs are recognized in the period in which the credits are generated. The Company had state investment and other tax credit carryforwards totaling $345 million at December 31, 2016, which will expire between 2019 and 2027 and are expected to be fully utilized by 2023. 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: 2016 2015 (in millions) Generation $ 16,668 $ 15,386 Transmission 5,779 5,355 Distribution 9,553 9,151 General 1,813 1,921 Plant acquisition adjustment 28 28 Total plant in service $ 33,841 $ 31,841 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.8% in 2016 , 2.7% in 2015 , and 2.7% in 2014 . Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Under the terms of the 2013 ARP, the Company amortized approximately $14 million in each of 2014, 2015, and 2016 of its remaining regulatory liability related to other cost of removal obligations. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual and recovery of other retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for future obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheets as a regulatory asset. The ARO liability primarily relates to the Company's ash ponds, landfills, and gypsum cells that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 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: 2016 2015 (in millions) Balance at beginning of year $ 1,916 $ 1,255 Liabilities incurred — 6 Liabilities settled (123 ) (30 ) Accretion 77 56 Cash flow revisions 662 629 Balance at end of year $ 2,532 $ 1,916 The increase in cash flow revisions in 2016 is primarily related to changes to the Company's closure strategy for ash ponds, landfills, and gypsum cells AROs. The increase in cash flow revisions in 2015 is primarily related to changes to the Company's ash ponds, landfills, and gypsum cells ARO closure dollar and timing estimates associated with the CCR Rule and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, 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 with respect to compliance activities, 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. 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, 2016 and 2015 , approximately $56 million and $76 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 $58 million and $78 million at December 31, 2016 and 2015 , 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, 2016 , investment securities in the Funds totaled $814 million , consisting of equity securities of $326 million , debt securities of $477 million , and $11 million of other securities. 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. 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 $803 million , $980 million , and $669 million in 2016 , 2015 , and 2014 , respectively, all of which were reinvested. For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $38 million , which included $14 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $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 . 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
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 the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), Inc. (PowerSecure), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The equity method is used for entities in which the Company has significant influence but does not control. The Company is subject to regulation by the FERC and the Florida PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 11 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. 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 $80 million , $81 million , and $80 million during 2016 , 2015 , and 2014 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8 million , $12 million , and $9 million and Mississippi Power $26 million , $27 million , and $31 million in 2016 , 2015 , and 2014 , 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 made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. Payments by the Company to Alabama Power for the improvements were $12 million , $14 million , and $12 million in 2016 , 2015 , and 2014 , respectively, and are expected to be approximately $10 million annually for 2017 through 2023 , when the PPA expires. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff. In 2016, the Company purchased a turbine rotor assembly from Southern Power for $6.8 million . The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . The traditional electric operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans, net $ 160 $ 147 (a,b) PPA charges 141 163 (b,c) Closure of ash ponds 75 29 (b,d) Remaining book value of retired assets 66 4 (e) Deferred income tax charges 56 59 (f) Environmental remediation 44 46 (b,d) Regulatory asset, offset to other cost of removal 29 29 (g) Deferred return on transmission upgrades 25 10 (g) Fuel-hedging assets, net 24 104 (b,h) Other regulatory assets, net 18 16 (i) Loss on reacquired debt 18 15 (j) Asset retirement obligations, net 7 (1 ) (b,f) Other cost of removal obligations (278 ) (262 ) (f) Property damage reserve (40 ) (38 ) (e) Over recovered regulatory clause revenues (23 ) (22 ) (k) Deferred income tax credits (2 ) (3 ) (f) Total regulatory assets (liabilities), net $ 320 $ 296 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (b) Not earning a return as offset in rate base by a corresponding asset or liability. (c) Recovered over the life of the PPA for periods up to seven years . (d) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (e) Recorded and recovered or amortized as approved by the Florida PSC. (f) Asset retirement and removal assets and liabilities are recorded, 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. (g) Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. (h) 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. (i) Comprised primarily of vacation pay. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year . (j) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years . (k) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 3,001 $ 2,974 Transmission 706 691 Distribution 1,241 1,196 General 191 182 Plant acquisition adjustment 1 2 Total plant in service $ 5,140 $ 5,045 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% in both 2016 and 2015 and 3.6% in 2014 . 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 Cases" for additional information. Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 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: 2016 2015 (in millions) Balance at beginning of year $ 130 $ 17 Liabilities incurred 1 105 Liabilities settled (1 ) (1 ) Accretion 4 2 Cash flow revisions 2 7 Balance at end of year $ 136 $ 130 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 and the closure of an ash pond at Plant Scholz. 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 in 2015. The cost estimates for AROs related to CCR are based on information as of December 31, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure for those facilities impacted by the CCR Rule. As further analysis is performed, 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 with respect to compliance activities, 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. Allowance for Funds Used During Construction The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for all years presented. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 0.00% , 10.80% , and 10.93% for 2016 , 2015 , and 2014 , 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 $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2016 , 2015 , and 2014 . As of December 31, 2016 and 2015 , the balance in the Company's property damage reserve totaled approximately $40 million and $38 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 under "Retail Regulatory Matters – Retail Base Rate Cases" 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 had a balance of $1.4 million at December 31, 2016 , which is included in current liabilities in the balance sheets. The balance was zero at December 31, 2015 . There were no liabilities in excess of the reserve balance at December 31, 2016 . 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. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. See Note 10 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . 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 Co
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 electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The Company is subject to regulation by the FERC and the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note s 5, 8, and 11 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. In 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern (ASU 2014-15). ASU 2014-15 defines management's responsibility to evaluate whether there is substantial doubt about an organization's ability to continue as a going concern within one year of the date the financial statements are issued and to provide related footnote disclosures including management's plans that alleviate substantial doubt. ASU 2014-15 became effective for fiscal years ending after December 15, 2016 and the Company has included the disclosures required by ASU 2014-15 in Note 6 under "Going Concern." 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 $231 million , $295 million , and $259 million during 2016 , 2015 , and 2014 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $13 million , $11 million , and $13 million in 2016 , 2015 , and 2014 , respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility. There were no fuel purchases in 2016. Fuel purchases were $8 million and $34 million in 2015 and 2014 , 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 $26 million , $27 million , and $31 million in 2016 , 2015 , and 2014 , respectively. See Note 4 for additional information. On June 27, 2016, the Company received a capital contribution from Southern Company of $225 million , the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of December 31, 2016 , the amount of outstanding promissory notes to Southern Company totaled $551 million . Also, on December 14, 2016, the Company received a capital contribution from Southern Company of $400 million , the proceeds of w hich were used for general corporate purposes. See Note 6 for additional information. The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described he rein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . The traditional electric operating companies, including the Company and S outhern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Kemper IGCC $ 201 $ 216 (h) Retiree benefit plans – regulatory assets 173 163 (a,g) Asset retirement obligations 83 70 (c) Deferred income tax charges 362 291 (c) Remaining net book value of retired assets 53 36 (b) Property tax 37 27 (d) Plant Daniel Units 3 and 4 33 29 (j) Other regulatory assets 42 27 (e,g) Fuel-hedging (realized and unrealized) losses 7 50 (f,g) Property damage (68 ) (64 ) (i) Other cost of removal obligations (170 ) (167 ) (c) Other regulatory liabilities (16 ) (11 ) (b) Total regulatory assets (liabilities), net $ 737 $ 667 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 m ay range up to 14 years . See Note 2 for additional information. (b) Other regulatory liabilities is comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year . (c) 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 49 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (d) The retail portion of property taxes is recovered through the ad valorem tax adjustment clause over a 12 -month period beginning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. (e) Other regulatory assets is comprised of numerous immaterial components including vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. (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) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two , seven , or 10 years . 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) The difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term is d eferred and amortized over a 10 -year period beginning October 2021. 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 agr eement 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 (Initial DOE Grants). Through December 31, 2016 , the Company has received grant funds of $382 million , of which $245 million of the Initial DOE Grants were used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $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 represent ed 19.8% of the Company's total operating revenues in 2016 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 above for the Company's cost-based MRA electric tariff customers, the Company has a diversified base of customers and no single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. See Note 3 under "Retail Regulatory Matters" for additional information. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. T axes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates. The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 2,632 $ 2,723 Transmission 712 688 Distribution 916 891 General 520 503 Plant acquisition adjustment 85 81 Total plant in service $ 4,865 $ 4,886 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 operations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. Through July 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 that is being recovered over 10 years beginning August 2015. 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 4.2% in 2016 , 4.7% in 2015 , and 3.3% in 2014 . The decrease in the 2016 depreciation rate is primarily due to fully depreciating and retiring the ARO at Plant Watson, partially offset by the increase in depreciation for the Plant Daniel scrubbers for a full year. The increase in the 2015 depreciation rate was primarily due to an 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. The Mississippi PSC approved the 2014 study, with new rates effective January 1, 2015. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities, except for the Kemper IGCC assets in service. 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 July 2015, depreciation associated with the combined cycle and the associated common facilities portion of the Kemper IGCC was deferred as a regulatory asset that is being recovered over 10 years beginning August 2015. 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 in April 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in th e statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as e ither a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 177 $ 48 Liabilities incurred 15 101 Liabilities settled (23 ) (3 ) Accretion 5 4 Cash flow revisions 5 27 Balance at end of year $ 179 $ 177 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, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, 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 with respect to compliance activities, 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. Allowance for Funds Used During Construction The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate w as 6.50% , 5.99% , and 6.91% for the years ended December 31, 2016 , 2015 , and 2014 , respectively. AFUDC equity was $124 million , $110 million , and $136 million in 2016 , 2015 , and 2014 , 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 exce ed $50,000 is charged to the reserve. Every three years the Mississippi PSC, the MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. The Company made retail accruals of $4 million for 2016 and $3 million for each of 2015 and 2014 . The Company also accrued $0.3 million annually in 2016 , 2015 , and 2014 for the wholesale jurisdiction. As of December 31, 2016 , the property damage reserve balances were $66 million and $1 million for retail and wholesa le, 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 used, 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 costs are recorded 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 coal is mined, 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 b
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 electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and 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. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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 In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The Company's ongoing evaluation of revenue streams and related contracts includes the evaluation of identified revenue streams tied to longer term contractual arrangements, such as certain capacity payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC Topic 840). The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. However, given the Company's core activities of selling generation capacity and energy to high credit rated customers, the Company currently does not expect the new standard to have a significant impact to net income. The Company has not elected a transition method as the ultimate impact of the new standard has not yet been determined. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. The Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of the Company. Affiliate Transactions Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $258 million , $219 million , and $153 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $109 million in both 2016 and 2015 and $75 million in 2014 . 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 totaled approximately $193 million , $146 million , and $126 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Of these costs, approximately $173 million , $138 million , and $125 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively, 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 also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $11 million in each of the years ended December 31, 2016 and 2015 and $7 million for the year ended December 31, 2014 , and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. For the period subsequent to Southern Company's acquisition of Southern Company Gas, from July 1, 2016 through December 31, 2016, natural gas purchases made by the Company from Southern Company Gas' subsidiaries were approximately $17 million and are included in fuel expense on the consolidated statements of income. On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016, transportation costs under this agreement were approximately $7 million . In 2016, the Company sold a turbine rotor assembly to Gulf Power for approximately $7 million . The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. Acquisition Accounting The Company 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. Contingent consideration recognized at the time of each acquisition primarily relates to fixed amounts due to the seller once the facility is successfully placed in service. To the extent there is any contingent consideration with variable payments, the Company fair values the arrangement with changes recorded in net income. See Note 8 for additional information. Revenues The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in 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. 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: 2016 2015 2014 Georgia Power 16.5 % 15.8 % 10.1 % Duke Energy Corporation 7.8 % 8.2 % 9.1 % San Diego Gas & Electric Company 5.7 % 6.1 % 2.9 % FPL — % 10.7 % 9.7 % Fuel Costs Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2016 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information. Property, Plant, and Equipment The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred. When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income. Depreciation The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets. The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows: Generating facility Useful life Natural gas Up to 45 years Biomass Up to 40 years Solar Up to 35 years Wind Up to 30 years The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. Asset Retirement Obligations Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 2 for acquisitions during 2015 and 2016 which contributed to the increased liability. Details of the AROs included on the consolidated balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 21 $ 13 Liabilities incurred 42 7 Accretion 1 1 Balance at end of year $ 64 $ 21 Long-Term Service Agreements The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the statements of cash flows. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the PPA. The average term of these PPAs is 19 years . The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. Amortization expense for acquired PPAs was $10 million for the year ended December 31, 2016 and $3 million for each of the years ended December 31, 2015 and 2014 , and is recorded in operating revenues. The amortization expense for each of the next five years is as follows: Amortization Expense (in millions) 2017 $ 25 2018 25 2019 25 2020 25 2021 25 Transmission Receivables/Prepayments As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five -year period and the receivable/prepayments are reduced as payments or services are received. Restricted Cash The use of funds received under credit facilities for Garland, Roserock, and Tranquillity is restricted for construction purposes. In addition, as a result of the Wake Wind acquisition, cash was received and is restricted for final completion payments related to construction. The aggregate amount of restricted cash at December 31, 2016 and 2015 was $13 million and $5 million , respectively, 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 include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment. Fuel Inventory Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several natural gas generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other" 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. Beginning in 2016, the Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . 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.
Southern Company Gas [Member]
Summary of Significant Accounting Policies [Line Items]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General On July 1, 2016, Southern Company and Southern Company Gas (formerly known as AGL Resources Inc.) (together with its subsidiaries, the Company) completed the Merger and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company and, on July 11, 2016, changed its name to Southern Company Gas. In addition to the Company, Southern Company is the parent company of four traditional electric operating companies, Southern Power, Southern Company Services, Inc. (SCS), Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc., and other direct and indirect subsidiaries. Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas across seven states through its seven natural gas distribution utilities. The Company also is involved in several other businesses that are complementary to the distribution of natural gas. The traditional electric operating companies – Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power 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. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure, Inc. is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect the Company's investments in its subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for VIEs where the Company has an equity investment, but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The seven natural gas distribution utilities are subject to regulation by the regulatory agencies of each state in which they operate. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Pursuant to the Merger, Southern Company has pushed down the application of the acquisition method of accounting to the consolidated financial statements of the Company such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of the Company for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout the consolidated financial statements and notes to the financial statements, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor." Certain predecessor period data presented in the financial statements has been modified or reclassified to conform to the presentation used by the Company's new parent company, Southern Company. Changes to the consolidated statements of income include classifying operating revenues as natural gas revenues and other revenues as well as classifying cost of goods sold as cost of natural gas and cost of other sales, and presenting interest expense and AFUDC on a gross basis. Changes to the consolidated statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each category of cash flow activity. Changes to the consolidated balance sheets include changing certain captions to conform to the presentation of Southern Company. Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. 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 in 2016. 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 adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note 5 for the disclosure impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. The Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of the Company. Affiliate Transactions Prior to the Company's completion of its acquisition of a 50% equity interest in SNG, the Company entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to the Company's investment in SNG, transportation costs paid to SNG by the Company were approximately $15 million . See Note 4 herein under "Equity Method Investments – SNG" for additional information regarding the Company's investment in SNG. The Company has an agreement with SCS under which the following services are currently being rendered to the Company as direct or allocated cost: accounting, finance and treasury, tax, information technology, auditing, insurance and pension administration, human resources, systems and procedures, purchasing, and other services. For the successor period of July 1, 2016 through December 31, 2016 , costs for these services amounted to $17 million . SouthStar and Sequent each have agreements under which they sell natural gas to SCS, as agent for the traditional electric operating companies and Southern Power. For the successor period of July 1, 2016 through December 31, 2016 , revenue from these agreements totaled $9 million and $19 million , respectively. Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: Successor Predecessor 2016 2015 Note (in millions) (in millions) Deferred income tax credits $ (22 ) $ (27 ) (a) Long-term debt fair value adjustment 154 66 (b) Environmental remediation - asset 411 401 (h) Under recovered regulatory clause revenues 118 69 (c) Financial instrument hedging - asset — 30 (d,h) Other regulatory assets 58 47 (e) Other cost of removal obligations (1,616 ) (1,591 ) (a) Financial instrument hedging - liability (21 ) — (d,h) Other regulatory liabilities (18 ) (20 ) (f) Retiree benefit plans 325 125 (g,h) Over recovered regulatory clause revenues (104 ) (87 ) (c) Total regulatory assets (liabilities), net $ (715 ) $ (987 ) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Deferred income tax assets and liabilities are amortized over the related property lives, which range up to 30 years . (b) Recovered over the remaining life of the original debt issuances, which range up to 22 years . (c) Recorded and recovered or amortized as approved or accepted by the applicable state regulatory agencies over periods not exceeding nine years . (d) Financial instrument-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years . Upon final settlement, actual costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause. (e) Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, and deferred depreciation expense, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding ten years . (f) Comprised of several components including energy efficiency programs and unamortized bond issuance costs which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding four years . (g) Recovered and amortized over the average remaining service period which range up to 11 years . See Note 2 for additional information. (h) Not earning a return as offset in rate base by a corresponding asset or liability. In the event that a portion of its operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the 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 "Regulatory Matters" for additional information. Revenues Gas Distribution Operations The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the Company's utilities. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. All of the natural gas utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period. The tariffs for Virginia Natural Gas, Elizabethtown Gas, and Chattanooga Gas contain weather normalization adjustments (WNAs) that partially mitigate the impact of unusually cold or warm weather on customer billings and natural gas revenues. The WNAs have the effect of reducing customer bills when winter weather is colder than normal and increasing customer bills when weather is warmer than normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas, and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage. The WNAs and revenue normalization mechanisms are alternative revenue programs, which allow recognition of revenue prior to billing as long as the amounts will be collected within 24 months of recognition. Revenue Taxes The Company charges customers for gas revenue and gas use taxes imposed on the Company and remits amounts owed to various governmental authorities. Gas revenue taxes are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on the Company are recorded as operating expenses on the statements of income. Gas use taxes are excluded from revenue and expense with the related administrative fee included in operating revenues when the tax is imposed on the customer. Revenue taxes included in operating expenses were $31 million for the successor period of July 1, 2016 through December 31, 2016 and $56 million , $101 million , and $130 million for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , respectively. Gas Marketing Services The Company recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. The Company also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period. The Company recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. Revenues for warranty and repair contracts are recognized on a straight-line basis over the contract term while revenues for maintenance services are recognized at the time such services are performed. Wholesale Gas Services The Company nets revenues from energy and risk management activities with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. The Company records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue. Concentration of Revenue The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Cost of Natural Gas and Other Sales Gas Distribution Operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the Company charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the consolidated balance sheets as regulatory assets and regulatory liabilities, respectively. Gas Marketing Services The Company's gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, the Company also includes costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives. The Company records the costs to service its warranty and repair contract claims as cost of other sales. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheet, excluding revenue taxes which are presented on the statements of income. See "Revenues – Gas Distribution Operations – Revenue Taxes" herein for additional information. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost, or fair value at the effective date of the Merger as appropriate, less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: Successor Predecessor 2016 2015 (in millions) (in millions) Utility plant in service $ 11,996 $ 9,912 Information technology equipment and software 324 415 Storage facilities 1,463 1,255 Other 725 570 Total other plant in service 2,512 2,240 Total plant in service $ 14,508 $ 12,152 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. The portion of pad gas at the Company's natural gas storage facilities considered to be non-recoverable is recorded as depreciable property, plant, and equipment, while the recoverable or retained portion is recorded as non-depreciable property, plant, and equipment. The amount of non-cash property additions recognized for the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 was $63 million , $41 million , $48 million , and $31 million , respectively. These amounts are comprised of construction-related accounts payable outstanding at the end of each period. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.8% in 2016 and 2.7% in each of 2015 and 2014. Depreciation studies are conducted periodically to update the composite rates that are approved by the respective state regulatory agency. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the asset are retired when the related property unit is retired. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over the following useful lives: five to 15 years for transportation equipment, 40 to 60 years for storage facilities, and up to 65 years for other assets. Allowance for Funds Used During Construction The Company records AFUDC for Atlanta Gas Light, Nicor Gas, Chattanooga Gas, and Elizabethtown Gas, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The capital expenditures of the other three natural gas utilities do not qualify for AFUDC treatment. The Company's AFUDC composite rates are as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years ended December 31, 2016 2016 2015 2014 Atlanta Gas Light 4.05 % 4.05 % 8.10 % 8.10 % Chattanooga Gas (*) 3.71 3.71 7.41 7.41 Elizabethtown Gas (*) 0.84 0.84 1.69 0.44 Nicor Gas (*) 1.50 1.50 0.82 0.24 (*) Variable rate is determined by the FERC method of AFUDC accounting. Cash payments for interest during the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 totaled $135 million , $119 million , $181 million , and $187 million , respectively. Goodwill and Other Intangible Assets and Liabilities Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any. The Company performed Step 1 of the impairment test in the fourth quarter 2014, which resulted in the fair values of all reporting units with goodwill exceeding their respective carrying value. However, the Company noted that the fair value of the storage and fuels reporting unit, which had $14 million of goodwill, exceeded its carrying value by less than 5% and would be at risk of failing Step 1 of the test if a further decline in fair value were to occur. While preparing the third quarter 2015 financial statements, and in connection with the 2016 annual budget process, the Company concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit's profitability required an interim goodwill impairment test to be performed as of September 30, 2015. The Company performed Step 1 and Step 2 for the interim goodwill impairment test. Based on this assessment, a non-cash impairment charge for the entire $14 million of goodwill was recorded as of September 30, 2015. For the 2016 and 2015 annual goodwill impairment tests, the Step 0 assessment was performed focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. This Step 0 analysis concluded that it is more likely than not that the fair value of the Company's reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required. Goodwill and other intangible assets consisted of the following: Successor - At December 31, 2016 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Intangible Assets, Net (in millions) Other intangible assets subject to amortization: Gas marketing services Customer relationships 11-14 years $ 221 $ (30 ) $ 191 Trade names 10-28 years 115 (2 ) 113 Wholesale gas services Storage and transportation contracts 1-5 years 64 (2 ) 62 Total intangible assets subject to amortization $ 400 $ (34 ) $ 366 Goodwill: Gas distribution operations (*) $ 4,702 $ — 4,702 Gas marketing services 1,265 — 1,265 Total goodwill $ 5,967 $ — $ 5,967 (*) Measurement period adjustments were recorded in acquisition accounting during the fourth quarter 2016 that resulted in a net $30 million increase to goodwill. Predecessor - At December 31, 2015 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Intangible Assets, Net (in millions) Other intangible assets subject to amortization: Gas marketing services Customer relationships 11-14 years $ 132 $ (57 ) $ 75 Trade names 10-28 years 45 (11 ) 34 Total intangible assets subject to amortization $ 177 $ (68 ) $ 109 Goodwill: Gas distribution operations $ 1,640 $ — $ 1,640 Gas marketing services 173 — 173 Total goodwill $ 1,813 $ — $ 1,813 Amortization associated with intangible assets during the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 was $32 million , $8 million , $18 million , and $20 million , respectively. Amortization of $2 million for wholesale gas services is recorded as a reduction to operating revenues. The increases in goodwill and other intangible assets relate to purchase accounting adjustments associated with the Merger. See Note 11 under "Merger with Southern Company" for

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
RETIREMENT BENEFITS	RETIREMENT BENEFITS Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On December 19, 2016, the traditional electric operating companies and certain other subsidiaries voluntarily contributed an aggregate of $900 million to Southern Company's qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017 . Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2017 , no other postretirement trust contributions are expected. In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. Southern Company Gas voluntarily contributed $125 million to its qualified pension plan on September 12, 2016. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2017 , 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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.58 % 4.17 % 5.02 % Discount rate – interest costs 3.88 4.17 5.02 Discount rate – service costs 4.98 4.48 5.02 Expected long-term return on plan assets 8.16 8.20 8.20 Annual salary increase 4.37 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.38 % 4.04 % 4.85 % Discount rate – interest costs 3.66 4.04 4.85 Discount rate – service costs 4.85 4.39 4.85 Expected long-term return on plan assets 6.66 6.97 7.15 Annual salary increase 4.37 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.40 % 4.67 % Annual salary increase 4.37 4.46 Other postretirement benefit plans Discount rate 4.23 % 4.51 % Annual salary increase 4.37 4.46 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of 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. 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, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent 1 Percent (in millions) Benefit obligation $ 128 $ 110 Service and interest costs 4 3 Pension Plans The total accumulated benefit obligation for the pension plans was $11.3 billion at December 31, 2016 and $9.6 billion at December 31, 2015 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 10,542 $ 10,909 Acquisitions 1,244 — Service cost 262 257 Interest cost 422 445 Benefits paid (466 ) (487 ) Actuarial (gain) loss 381 (582 ) Balance at end of year 12,385 10,542 Change in plan assets Fair value of plan assets at beginning of year 9,234 9,690 Acquisitions 837 — Actual return (loss) on plan assets 902 (14 ) Employer contributions 1,076 45 Benefits paid (466 ) (487 ) Fair value of plan assets at end of year 11,583 9,234 Accrued liability $ (802 ) $ (1,308 ) At December 31, 2016 , the projected benefit obligations for the qualified and non-qualified pension plans were $11.8 billion and $627 million , respectively. All pension plan assets are related to the qualified pension plans. Amounts presented in the following tables do not include regulatory assets of $369 million recognized by Southern Company Gas associated with its pension plans prior to its acquisition on July 1, 2016. Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 3,207 $ 2,998 Other current liabilities (53 ) (46 ) Employee benefit obligations (749 ) (1,262 ) Other regulatory liabilities, deferred (87 ) — Accumulated OCI 100 125 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 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 2017 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2016: Accumulated OCI $ 4 $ 96 Regulatory assets 51 3,069 Total $ 55 $ 3,165 Balance at December 31, 2015: Accumulated OCI $ 3 $ 122 Regulatory assets 27 2,971 Total $ 30 $ 3,093 Estimated amortization in net periodic pension cost in 2017: Accumulated OCI $ 1 $ 7 Regulatory assets 11 155 Total $ 12 $ 162 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, 2016 and 2015 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2014 $ 134 $ 3,073 Net (gain) loss 1 155 Reclassification adjustments: Amortization of prior service costs (1 ) (24 ) Amortization of net gain (loss) (9 ) (206 ) Total reclassification adjustments (10 ) (230 ) Total change (9 ) (75 ) Balance at December 31, 2015 $ 125 $ 2,998 Net (gain) loss (20 ) 243 Change in prior service costs 2 37 Reclassification adjustments: Amortization of prior service costs (1 ) (13 ) Amortization of net gain (loss) (6 ) (145 ) Total reclassification adjustments (7 ) (158 ) Total change (25 ) 122 Balance at December 31, 2016 $ 100 $ 3,120 Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 262 $ 257 $ 213 Interest cost 422 445 435 Expected return on plan assets (782 ) (724 ) (645 ) Recognized net (gain) loss 150 215 110 Net amortization 14 25 26 Net periodic pension cost $ 66 $ 218 $ 139 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, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 571 2018 593 2019 620 2020 646 2021 666 2022 to 2026 3,673 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 1,989 $ 1,986 Acquisitions 338 — Service cost 22 23 Interest cost 76 78 Benefits paid (119 ) (102 ) Actuarial (gain) loss (16 ) (38 ) Plan amendments — 34 Retiree drug subsidy 7 8 Balance at end of year 2,297 1,989 Change in plan assets Fair value of plan assets at beginning of year 833 900 Acquisitions 100 — Actual return (loss) on plan assets 58 (12 ) Employer contributions 65 39 Benefits paid (112 ) (94 ) Fair value of plan assets at end of year 944 833 Accrued liability $ (1,353 ) $ (1,156 ) Amounts presented in the following tables do not include regulatory assets of $77 million recognized by Southern Company Gas associated with its other postretirement benefit plan prior to its acquisition on July 1, 2016. Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 419 $ 433 Other current liabilities (4 ) (4 ) Employee benefit obligations (1,349 ) (1,152 ) Other regulatory liabilities, deferred (41 ) (22 ) Accumulated OCI 7 8 Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2016 and 2015 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 2017 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2016: Accumulated OCI $ — $ 7 Net regulatory assets 25 353 Total $ 25 $ 360 Balance at December 31, 2015: Accumulated OCI $ — $ 8 Net regulatory assets 32 379 Total $ 32 $ 387 Estimated amortization as net periodic postretirement benefit cost in 2017: Net regulatory assets $ 6 $ 13 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, 2016 and 2015 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2014 $ 8 $ 366 Net (gain) loss — 33 Change in prior service costs — 33 Reclassification adjustments: Amortization of prior service costs — (4 ) Amortization of net gain (loss) — (17 ) Total reclassification adjustments — (21 ) Total change — 45 Balance at December 31, 2015 $ 8 $ 411 Net (gain) loss (1 ) (13 ) Reclassification adjustments: Amortization of prior service costs — (6 ) Amortization of net gain (loss) — (14 ) Total reclassification adjustments — (20 ) Total change (1 ) (33 ) Balance at December 31, 2016 $ 7 $ 378 Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 22 $ 23 $ 21 Interest cost 76 78 79 Expected return on plan assets (60 ) (58 ) (59 ) Net amortization 21 21 6 Net periodic postretirement benefit cost $ 59 $ 64 $ 47 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) 2017 $ 145 $ (10 ) $ 135 2018 150 (11 ) 139 2019 155 (12 ) 143 2020 159 (13 ) 146 2021 162 (14 ) 148 2022 to 2026 823 (73 ) 750 Benefit Plan Assets Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The investment strategy for plan assets related to the Company's qualified pension plans is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plans is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company plan employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies and Benefit Plan Asset Fair Values A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below: Description Valuation Methodology ● Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. ● International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. ● Fixed income: A mix of domestic and international bonds. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. ● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. ● Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature. ● Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. ● Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values, and actual allocations relative to the target allocations, of Southern Company's pension plan (excluding Southern Company Gas) as of December 31, 2016 and 2015 are presented below. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 2,010 $ 927 $ — $ — $ 2,937 26 % 29 % International equity (*) 1,231 1,110 — — 2,341 25 22 Fixed income: 23 29 U.S. Treasury, government, and agency bonds — 588 — — 588 Mortgage- and asset-backed securities — 13 — — 13 Corporate bonds — 991 — — 991 Pooled funds — 524 — — 524 Cash equivalents and other 996 2 — — 998 Real estate investments 310 — — 1,152 1,462 14 13 Special situations — — 180 180 3 2 Private equity — — — 549 549 9 5 Total $ 4,547 $ 4,155 $ — $ 1,881 $ 10,583 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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 Target Allocation Actual Allocation As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (a) $ 1,632 $ 681 $ — $ — $ 2,313 26 % 30 % International equity (a) 1,190 962 — — 2,152 25 23 Fixed income: 23 23 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 — — 1,185 1,484 14 16 Special situations (b) — — — 160 160 3 2 Private equity — — — 536 536 9 6 Total $ 3,121 $ 4,081 $ — $ 1,881 $ 9,083 100 % 100 % Liabilities: Derivatives $ (1 ) $ — $ — $ — $ (1 ) Total $ 3,120 $ 4,081 $ — $ 1,881 $ 9,082 100 % 100 % (a) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. (b) The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation. The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The assets of Southern Company Gas' pension plan were allocated 69% equity, 20% fixed income, 1% cash, and 10% other at December 31, 2016 , compared to the asset class targets of 53% equity, 15% fixed income, 2% cash, and 30% other. Southern Company Gas' pension plan investment policy provides for variation around the target asset allocation in the form of ranges. The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Total Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 118 $ 28 $ — $ — $ 146 39 % 40 % International equity (*) 37 61 — — 98 23 21 Fixed income: 29 31 U.S. Treasury, government, and agency bonds — 24 — — 24 Corporate bonds — 30 — — 30 Pooled funds — 49 — — 49 Cash equivalents and other 41 — — — 41 Trust-owned life insurance — 382 — — 382 Real estate investments 11 — — 35 46 5 5 Special situations — — — 5 5 1 1 Private equity — — — 17 17 3 2 Total $ 207 $ 574 $ — $ 57 $ 838 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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 Target Allocation Actual Allocation As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (a) $ 106 $ 52 $ — $ — $ 158 42 % 38 % International equity (a) 40 63 — — 103 21 23 Fixed income: 28 30 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 — — 40 51 5 6 Special situations (b) — — — 5 5 1 1 Private equity — — — 18 18 3 2 Total $ 168 $ 603 $ — $ 63 $ 834 100 % 100 % (a) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. (b) The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation. The fair values of Southern Company Gas' other postretirement benefit plan assets for the period ended December 31, 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient Total As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. The assets of Southern Company Gas' other postretirement benefit plans were allocated 74% equity, 23% fixed income, 1% cash, and 2% other at December 31, 2016 , compared to the asset class targets of 72% equity, 24% fixed income, 1% cash, and 3% other. Southern Company Gas' other postretirement plan's investment policy provides for some variation in these targets in the form of ranges around the target. Employee Savings Plan Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2016 , 2015 , and 2014 were $105 million , $92 million , and $87 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). On December 19, 2016, the Company voluntarily contributed $129 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017 . 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, 2017 , 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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.67 % 4.18 % 5.02 % Discount rate – interest costs 3.90 4.18 5.02 Discount rate – service costs 5.07 4.49 5.02 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.51 % 4.04 % 4.86 % Discount rate – interest costs 3.69 4.04 4.86 Discount rate – service costs 4.96 4.40 4.86 Expected long-term return on plan assets 6.83 7.17 7.34 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.44 % 4.67 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.27 % 4.51 % Annual salary increase 4.46 4.46 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of 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. 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, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 28 $ 24 Service and interest costs 1 1 Pension Plans The total accumulated benefit obligation for the pension plans was $2.4 billion at December 31, 2016 and $2.3 billion at December 31, 2015 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,506 $ 2,592 Service cost 57 59 Interest cost 95 106 Benefits paid (109 ) (120 ) Actuarial (gain) loss 114 (131 ) Balance at end of year 2,663 2,506 Change in plan assets Fair value of plan assets at beginning of year 2,279 2,396 Actual return (loss) on plan assets 206 (9 ) Employer contributions 141 12 Benefits paid (109 ) (120 ) Fair value of plan assets at end of year 2,517 2,279 Accrued liability $ (146 ) $ (227 ) At December 31, 2016 , the projected benefit obligations for the qualified and non-qualified pension plans were $2.5 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, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 870 $ 822 Other current liabilities (12 ) (11 ) Employee benefit obligations (134 ) (216 ) Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 10 $ 6 $ 3 Net (gain) loss 860 816 42 Regulatory assets $ 870 $ 822 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 822 $ 827 Net (gain) loss 84 56 Change in prior service costs 7 — Reclassification adjustments: Amortization of prior service costs (3 ) (6 ) Amortization of net gain (loss) (40 ) (55 ) Total reclassification adjustments (43 ) (61 ) Total change 48 (5 ) Ending balance $ 870 $ 822 Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 57 $ 59 $ 48 Interest cost 95 106 103 Expected return on plan assets (184 ) (178 ) (168 ) Recognized net (gain) loss 40 55 31 Net amortization 3 6 7 Net periodic pension cost $ 11 $ 48 $ 21 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, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 122 2018 127 2019 132 2020 137 2021 142 2022 to 2026 777 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 505 $ 503 Service cost 5 6 Interest cost 18 20 Benefits paid (28 ) (27 ) Actuarial (gain) loss (1 ) (7 ) Plan amendment — 7 Retiree drug subsidy 2 3 Balance at end of year 501 505 Change in plan assets Fair value of plan assets at beginning of year 363 392 Actual return (loss) on plan assets 23 (6 ) Employer contributions 7 1 Benefits paid (26 ) (24 ) Fair value of plan assets at end of year 367 363 Accrued liability $ (134 ) $ (142 ) Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 86 $ 95 Other regulatory liabilities, deferred (10 ) (13 ) Employee benefit obligations (134 ) (142 ) Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 15 $ 19 $ 4 Net (gain) loss 61 63 1 Net regulatory assets $ 76 $ 82 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Net regulatory assets (liabilities): Beginning balance $ 82 $ 54 Net (gain) loss — 25 Change in prior service costs — 8 Reclassification adjustments: Amortization of prior service costs (4 ) (3 ) Amortization of net gain (loss) (2 ) (2 ) Total reclassification adjustments (6 ) (5 ) Total change (6 ) 28 Ending balance $ 76 $ 82 Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 5 $ 6 $ 5 Interest cost 18 20 20 Expected return on plan assets (25 ) (26 ) (25 ) Net amortization 6 5 4 Net periodic postretirement benefit cost $ 4 $ 5 $ 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) 2017 $ 32 $ (3 ) $ 29 2018 33 (3 ) 30 2019 34 (4 ) 30 2020 35 (4 ) 31 2021 36 (4 ) 32 2022 to 2026 183 (22 ) 161 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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 46 % 44 % 45 % International equity 22 20 20 Domestic fixed income 24 29 27 Special situations 1 1 1 Real estate investments 4 4 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, 2016 and 2015 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. • Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 477 $ 220 $ — $ — $ 697 International equity (*) 292 264 — — 556 Fixed income: U.S. Treasury, government, and agency bonds — 140 — — 140 Mortgage- and asset-backed securities — 3 — — 3 Corporate bonds — 235 — — 235 Pooled funds — 124 — — 124 Cash equivalents and other 236 1 — — 237 Real estate investments 74 — — 274 348 Special situations — — — 43 43 Private equity — — — 130 130 Total $ 1,079 $ 987 $ — $ 447 $ 2,513 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 51 $ 10 $ — $ — $ 61 International equity (*) 13 12 — — 25 Fixed income: U.S. Treasury, government, and agency bonds — 7 — — 7 Mortgage- and asset-backed securities — — — — — Corporate bonds — 10 — — 10 Pooled funds — 5 — — 5 Cash equivalents and other 14 — — — 14 Trust-owned life insurance — 220 — — 220 Real estate investments 4 — — 12 16 Special situations — — — 2 2 Private equity — — — 6 6 Total $ 82 $ 264 $ — $ 20 $ 366 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. 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 2016 , 2015 , and 2014 were $23 million , $22 million , and $21 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). On December 19, 2016, the Company voluntarily contributed $287 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017 . 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, 2017 , 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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.65 % 4.18 % 5.02 % Discount rate – interest costs 3.86 4.18 5.02 Discount rate – service costs 5.03 4.49 5.02 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.49 % 4.03 % 4.85 % Discount rate – interest costs 3.67 4.03 4.85 Discount rate – service costs 4.88 4.39 4.85 Expected long-term return on plan assets 6.27 6.48 6.75 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.40 % 4.65 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.23 % 4.49 % Annual salary increase 4.46 4.46 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of 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. 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, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 55 $ 48 Service and interest costs 2 2 Pension Plans The total accumulated benefit obligation for the pension plans was $3.5 billion at December 31, 2016 and $3.3 billion at December 31, 2015 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 3,615 $ 3,781 Service cost 70 73 Interest cost 136 154 Benefits paid (164 ) (188 ) Actuarial (gain) loss 143 (205 ) Balance at end of year 3,800 3,615 Change in plan assets Fair value of plan assets at beginning of year 3,196 3,383 Actual return (loss) on plan assets 288 (13 ) Employer contributions 301 14 Benefits paid (164 ) (188 ) Fair value of plan assets at end of year 3,621 3,196 Accrued liability $ (179 ) $ (419 ) At December 31, 2016 , the projected benefit obligations for the qualified and non-qualified pension plans were $3.6 billion and $152 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 1,129 $ 1,076 Other current liabilities (14 ) (13 ) Employee benefit obligations (165 ) (406 ) Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 17 $ 8 $ 3 Net (gain) loss 1,112 1,068 57 Regulatory assets $ 1,129 $ 1,076 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 1,076 $ 1,102 Net (gain) loss 99 59 Change in prior service costs 14 — Reclassification adjustments: Amortization of prior service costs (5 ) (9 ) Amortization of net gain (loss) (55 ) (76 ) Total reclassification adjustments (60 ) (85 ) Total change 53 (26 ) Ending balance $ 1,129 $ 1,076 Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 70 $ 73 $ 62 Interest cost 136 154 153 Expected return on plan assets (258 ) (251 ) (228 ) Recognized net (gain) loss 55 76 41 Net amortization 5 9 10 Net periodic pension cost $ 8 $ 61 $ 38 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, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 184 2018 190 2019 196 2020 202 2021 206 2022 to 2026 1,126 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 854 $ 864 Service cost 6 7 Interest cost 30 34 Benefits paid (45 ) (45 ) Actuarial (gain) loss (1 ) (22 ) Plan amendment — 12 Retiree drug subsidy 3 4 Balance at end of year 847 854 Change in plan assets Fair value of plan assets at beginning of year 358 395 Actual return (loss) on plan assets 21 (6 ) Employer contributions 17 10 Benefits paid (42 ) (41 ) Fair value of plan assets at end of year 354 358 Accrued liability $ (493 ) $ (496 ) Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 213 $ 223 Employee benefit obligations (493 ) (496 ) Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 6 $ 8 $ 1 Net (gain) loss 207 215 8 Regulatory assets $ 213 $ 223 The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 223 $ 213 Net (gain) loss — 9 Change in prior service costs — 12 Reclassification adjustments: Amortization of prior service costs (1 ) — Amortization of net gain (loss) (9 ) (11 ) Total reclassification adjustments (10 ) (11 ) Total change (10 ) 10 Ending balance $ 213 $ 223 Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 6 $ 7 $ 6 Interest cost 30 34 34 Expected return on plan assets (22 ) (24 ) (25 ) Net amortization 10 11 2 Net periodic postretirement benefit cost $ 24 $ 28 $ 17 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) 2017 $ 54 $ (4 ) $ 50 2018 56 (5 ) 51 2019 58 (5 ) 53 2020 59 (5 ) 54 2021 60 (6 ) 54 2022 to 2026 303 (32 ) 271 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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 36 % 35 % 34 % International equity 24 24 27 Domestic fixed income 33 35 25 Global fixed income 8 Special situations 1 1 — Real estate investments 4 4 4 Private equity 2 1 2 Total 100 % 100 % 100 % The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2016 and 2015 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. • Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 686 $ 317 $ — $ — $ 1,003 International equity (*) 420 380 — — 800 Fixed income: U.S. Treasury, government, and agency bonds — 201 — — 201 Mortgage- and asset-backed securities — 4 — — 4 Corporate bonds — 338 — — 338 Pooled funds — 179 — — 179 Cash equivalents and other 340 1 — — 341 Real estate investments 106 — — 394 500 Special situations — — — 61 61 Private equity — — — 188 188 Total $ 1,552 $ 1,420 $ — $ 643 $ 3,615 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 45 $ 9 $ — $ — $ 54 International equity (*) 11 37 — — 48 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Mortgage- and asset-backed securities — — — — — Corporate bonds — 9 — — 9 Pooled funds — 38 — — 38 Cash equivalents and other 15 — — — 15 Trust-owned life insurance — 162 — — 162 Real estate investments 3 — — 11 14 Special situations — — — 2 2 Private equity — — — 5 5 Total $ 74 $ 260 $ — $ 18 $ 352 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. 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 2016 , 2015 , and 2014 were $27 million , $26 million , and $25 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). On December 19, 2016, the Company voluntarily contributed $48 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017 . 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, 2017 , 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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.71 % 4.18 % 5.02 % Discount rate – interest costs 3.97 4.18 5.02 Discount rate – service costs 5.04 4.48 5.02 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.51 % 4.04 % 4.86 % Discount rate – interest costs 3.68 4.04 4.86 Discount rate – service costs 4.88 4.38 4.86 Expected long-term return on plan assets 8.05 8.07 8.08 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.46 % 4.71 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.25 % 4.51 % Annual salary increase 4.46 4.46 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of 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. 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, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 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 $460 million at December 31, 2016 and $424 million at December 31, 2015 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 480 $ 491 Service cost 12 12 Interest cost 19 20 Benefits paid (17 ) (20 ) Actuarial (gain) loss 23 (23 ) Balance at end of year 517 480 Change in plan assets Fair value of plan assets at beginning of year 420 435 Actual return (loss) on plan assets 39 4 Employer contributions 49 1 Benefits paid (17 ) (20 ) Fair value of plan assets at end of year 491 420 Accrued liability $ (26 ) $ (60 ) At December 31, 2016 , the projected benefit obligations for the qualified and non-qualified pension plans were $494 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, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 153 $ 142 Other current liabilities (1 ) (1 ) Employee benefit obligations (25 ) (59 ) Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 3 $ 2 $ 1 Net (gain) loss 150 140 7 Regulatory assets $ 153 $ 142 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 142 $ 146 Net (gain) loss 16 6 Change in prior service costs 2 — Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (6 ) (9 ) Total reclassification adjustments (7 ) (10 ) Total change 11 (4 ) Ending balance $ 153 $ 142 Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 12 $ 12 $ 10 Interest cost 19 20 19 Expected return on plan assets (34 ) (32 ) (28 ) Recognized net (gain) loss 6 9 5 Net amortization 1 1 1 Net periodic pension cost $ 4 $ 10 $ 7 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, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 20 2018 22 2019 23 2020 24 2021 26 2022 to 2026 149 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 81 $ 78 Service cost 1 1 Interest cost 3 3 Benefits paid (4 ) (4 ) Actuarial (gain) loss 2 (1 ) Plan amendment — 4 Balance at end of year 83 81 Change in plan assets Fair value of plan assets at beginning of year 17 18 Actual return (loss) on plan assets 2 — Employer contributions 3 3 Benefits paid (4 ) (4 ) Fair value of plan assets at end of year 18 17 Accrued liability $ (65 ) $ (64 ) Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 11 $ 10 Other current liabilities (1 ) (1 ) Other regulatory liabilities, deferred (4 ) (5 ) Employee benefit obligations (64 ) (63 ) Approximately $7 million and $5 million was included in net regulatory assets at December 31, 2016 and 2015 , respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is immaterial. The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Net regulatory assets (liabilities): Beginning balance $ 5 $ 2 Net (gain) loss 2 1 Change in prior service costs — 2 Total change 2 3 Ending balance $ 7 $ 5 Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (1 ) (1 ) (1 ) Net periodic postretirement benefit cost $ 3 $ 3 $ 3 Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: Benefit Payments Subsidy Receipts Total (in millions) 2017 $ 5 $ — $ 5 2018 5 — 5 2019 6 (1 ) 5 2020 6 (1 ) 5 2021 6 (1 ) 5 2022 to 2026 30 (3 ) 27 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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 25 % 28 % 29 % International equity 24 21 22 Domestic fixed income 25 31 25 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2016 and 2015 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 93 $ 43 $ — $ — $ 136 International equity (*) 57 52 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 27 — — 27 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 47 — — 47 Pooled funds — 24 — — 24 Cash equivalents and other 46 — — — 46 Real estate investments 14 — — 53 67 Special situations — — — 8 8 Private equity — — — 25 25 Total $ 210 $ 194 $ — $ 86 $ 490 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 2 $ — $ — $ 5 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 8 $ 8 $ — $ 3 $ 19 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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 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. 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 2016 , 2015 , and 2014 were $5 million , $4 million , and $4 million , respectively.
Mississippi Power [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
RETIREMENT BENEFITS	RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On December 19, 2016, the Company voluntarily contributed $47 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017 . 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, 2017 , 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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.69 % 4.17 % 5.01 % Discount rate – interest costs 3.97 4.17 5.01 Discount rate – service costs 5.04 4.49 5.01 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.47 % 4.03 % 4.85 % Discount rate – interest costs 3.66 4.03 4.85 Discount rate – service costs 4.88 4.38 4.85 Expected long-term return on plan assets 7.07 7.23 7.30 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.44 % 4.69 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.22 % 4.47 % Annual salary increase 4.46 4.46 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of 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. 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, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 5 $ 4 Service and interest costs — — Pension Plans The total accumulated benefit obligation for the pension plans was $479 million at December 31, 2016 and $447 million at December 31, 2015 . Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 500 $ 513 Service cost 13 13 Interest cost 19 21 Benefits paid (20 ) (22 ) Actuarial (gain) loss 22 (25 ) Balance at end of year 534 500 Change in plan assets Fair value of plan assets at beginning of year 430 446 Actual return (loss) on plan assets 39 4 Employer contributions 50 2 Benefits paid (20 ) (22 ) Fair value of plan assets at end of year 499 430 Accrued liability $ (35 ) $ (70 ) At December 31, 2016 , the projected benefit obligations for the qualified and non-qualified pension plans were $504 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, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 154 $ 144 Other current liabilities (3 ) (3 ) Employee benefit obligations (32 ) (67 ) Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 3 $ 2 $ 1 Net (gain) loss 151 142 7 Regulatory assets $ 154 $ 144 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 144 $ 151 Net (gain) loss 16 4 Change in prior service costs 2 — Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (7 ) (10 ) Total reclassification adjustments (8 ) (11 ) Total change 10 (7 ) Ending balance $ 154 $ 144 Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 13 $ 13 $ 10 Interest cost 19 21 20 Expected return on plan assets (35 ) (33 ) (29 ) Recognized net (gain) loss 7 10 5 Net amortization 1 1 1 Net periodic pension cost $ 5 $ 12 $ 7 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, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 22 2018 23 2019 24 2020 26 2021 27 2022 to 2026 154 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 97 $ 96 Service cost 1 1 Interest cost 3 4 Benefits paid (6 ) (5 ) Actuarial (gain) loss 1 (1 ) Plan amendment — 1 Retiree drug subsidy 1 1 Balance at end of year 97 97 Change in plan assets Fair value of plan assets at beginning of year 23 24 Actual return (loss) on plan assets 1 — Employer contributions 4 3 Benefits paid (5 ) (4 ) Fair value of plan assets at end of year 23 23 Accrued liability $ (74 ) $ (74 ) Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 21 $ 21 Other regulatory liabilities, deferred (2 ) (3 ) Employee benefit obligations (74 ) (74 ) Approximately $19 million and $18 million was included in net regulatory assets at December 31, 2016 and 2015 , respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is $1 million . The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Net regulatory assets (liabilities): Beginning balance $ 18 $ 16 Net (gain) loss 2 — Change in prior service costs — 3 Reclassification adjustments: Amortization of net gain (loss) (1 ) (1 ) Total reclassification adjustments (1 ) (1 ) Total change 1 2 Ending balance $ 19 $ 18 Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 4 4 Expected return on plan assets (1 ) (2 ) (2 ) Net amortization 1 1 — Net periodic postretirement benefit cost $ 4 $ 4 $ 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) 2017 $ 6 $ (1 ) $ 5 2018 6 (1 ) 5 2019 7 (1 ) 6 2020 7 (1 ) 6 2021 7 (1 ) 6 2022 to 2026 36 (1 ) 35 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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 21 % 23 % 24 % International equity 20 18 18 Domestic fixed income 38 43 38 Special situations 3 2 2 Real estate investments 11 10 13 Private equity 7 4 5 Total 100 % 100 % 100 % The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2016 and 2015 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 95 $ 44 $ — $ — $ 139 International equity (*) 58 51 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 28 — — 28 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 46 — — 46 Pooled funds — 25 — — 25 Cash equivalents and other 47 — — — 47 Real estate investments 15 — — 54 69 Special situations — — — 8 8 Private equity — — — 26 26 Total $ 215 $ 195 $ — $ 88 $ 498 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Mortgage- and asset-backed securities — — — — — Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 9 $ 12 $ — $ 3 $ 24 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. 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 2016 , 2015 , and 2014 were $5 million each year.
Southern Company Gas [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
RETIREMENT BENEFITS	RETIREMENT BENEFITS Effective July 1, 2016, in connection with the Merger, SCS became the sponsor of the Company's pension and other post-retirement benefit plans. The Company has a qualified defined benefit, trusteed, pension plan – AGL Resources Inc. Retirement Plan – covering certain eligible employees, which was closed in 2012 to new employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On September 12, 2016, the Company voluntarily contributed $125 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017. The Company also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan – AGL Welfare Plan. The Company also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2017 , no other postretirement trust contributions are expected. In connection with the Merger, the Company performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. This valuation resulted in increases to the projected benefit obligations for the pension and other postretirement benefit plans of approximately $177 million and $20 million , respectively, a decrease in the fair value of pension plan assets of $10 million , and an increase in the fair value of other postretirement benefit plan assets of $1 million . The Company also recorded a related regulatory asset of $437 million related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates for the natural gas distribution utilities. The previously unrecognized prior service cost and actuarial gain/loss related to non-utility subsidiaries were eliminated through purchase accounting adjustments. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the periods presented and the benefit obligations as of the measurement date are presented below. Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, Assumptions used to determine net periodic costs: 2016 2016 2015 2014 Pension plans Discount rate – interest costs (a) 3.21 % 4.00 % 4.20 % 5.00 % Discount rate – service costs (a) 4.07 4.80 4.20 5.00 Expected long-term return on plan assets 7.75 7.80 7.80 7.80 Annual salary increase 3.50 3.70 3.70 3.70 Pension band increase (b) 2.00 2.00 2.00 2.00 Other postretirement benefit plans Discount rate – interest costs (a) 2.84 % 3.60 % 4.00 % 4.70 % Discount rate – service costs (a) 3.96 4.70 4.00 4.70 Expected long-term return on plan assets 5.93 6.60 7.80 7.80 Annual salary increase 3.50 3.70 3.70 3.70 (a) Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate. (b) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates of 2.0% for each of 2016 and 2017, in accordance with a March 2014 union agreement. Successor Predecessor Assumptions used to determine benefit obligations: December 31, 2016 December 31, 2015 Pension plans Discount rate 4.39 % 4.6 % Annual salary increase 3.50 3.7 Pension band increase (*) 2.00 2.0 Other postretirement benefit plans Discount rate 4.15 % 4.4 % Annual salary increase 3.50 3.7 (*) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates of 2.0% for each of 2016 and 2017, in accordance with a March 2014 union agreement. The Company estimates the expected return on plans assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year's annual pension or welfare plan cost; rather, this gain or loss reduces or increases future pension or welfare plan costs. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.60 % 4.50 % 2038 Post-65 medical 8.40 4.50 2038 Post-65 prescription 8.40 4.50 2038 An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components as follows: 1 Percent Increase 1 Percent Decrease (in millions) Successor – December 31, 2016 Benefit obligation $ 14 $ 12 Service and interest costs — — Pension Plans The total accumulated benefit obligation for the pension plans was $1.1 billion at December 31, 2016 and $1.0 billion at December 31, 2015 . Changes in the projected benefit obligations and the fair value of plan assets for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 were as follows: Successor Predecessor July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 2015 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 1,244 $ 1,067 $ 1,098 Service cost 15 13 28 Interest cost 20 21 45 Benefits paid (31 ) (26 ) (49 ) Actuarial loss (gain) (115 ) 169 (55 ) Balance at end of period 1,133 1,244 1,067 Change in plan assets Fair value of plan assets at beginning of period 837 847 906 Actual return (loss) on plan assets 48 15 (12 ) Employer contributions 129 1 2 Benefits paid (31 ) (26 ) (49 ) Fair value of plan assets at end of period 983 837 847 Accrued liability $ 150 $ 407 $ 220 At December 31, 2016 , the projected benefit obligations for the qualified and non-qualified pension plans were $1.1 billion and $39 million , respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the consolidated balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: Successor Predecessor 2016 2015 (in millions) (in millions) Other regulatory assets, deferred $ 267 $ 88 Other deferred charges and assets 58 78 Other current liabilities (2 ) (4 ) Employee benefit obligations (206 ) (294 ) Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 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 2017 . Prior Service Cost Net (Gain) Loss (in millions) Successor – Balance at December 31, 2016: Accumulated OCI $ — $ (43 ) Regulatory assets (liabilities) (2 ) 269 Total $ (2 ) $ 226 Predecessor – Balance at December 31, 2015: Accumulated OCI $ (4 ) $ 286 Regulatory assets — 88 Total $ (4 ) $ 374 Estimated amortization in net periodic cost in 2017: Regulatory assets (liabilities) $ 1 $ (21 ) The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2014: $ 301 $ 76 Net (gain) loss — 22 Reclassification adjustments: Amortization of prior service costs 2 — Amortization of net loss (21 ) (10 ) Total reclassification adjustments (19 ) (10 ) Total change (19 ) 12 Predecessor – Balance at December 31, 2015: $ 282 $ 88 Reclassification adjustments: Amortization of prior service costs 1 — Amortization of net loss (9 ) (4 ) Total reclassification adjustments (8 ) (4 ) Total change (8 ) (4 ) Predecessor – Balance at June 30, 2016: $ 274 $ 84 Successor – Balance at July 1, 2016: $ — $ 368 Net (gain) loss (43 ) (87 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (15 ) Total reclassification adjustments — (14 ) Total change (43 ) (101 ) Successor – Balance at December 31, 2016: $ (43 ) $ 267 Components of net periodic pension costs for the periods presented were as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 (in millions) (in millions) Service cost $ 15 $ 13 $ 28 $ 24 Interest cost 20 21 45 47 Expected return on plan assets (35 ) (33 ) (65 ) (65 ) Amortization of regulatory assets 13 — — — Amortization: Prior service costs — (1 ) (2 ) (2 ) Net (gain)/loss — 13 31 22 Net periodic pension cost $ 13 $ 13 $ 37 $ 26 Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 71 2018 72 2019 73 2020 74 2021 74 2022 to 2026 363 Other Postretirement Benefits Changes in the APBO and the fair value of plan assets for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 were as follows: Successor Predecessor July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 2015 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 338 $ 318 $ 334 Service cost 1 1 2 Interest cost 5 5 13 Benefits paid (11 ) (11 ) (20 ) Actuarial loss (gain) (26 ) 24 (13 ) Retiree drug subsidy — — 1 Employee contributions 1 1 1 Balance at end of period 308 338 318 Change in plan assets Fair value of plan assets at beginning of period 100 99 99 Actual return (loss) on plan assets 4 1 1 Employee contributions 1 1 1 Employer contributions 11 10 17 Benefits paid (11 ) (11 ) (20 ) Retiree drug subsidy — — 1 Fair value of plan assets at end of year 105 100 99 Accrued liability $ 203 $ 238 $ 219 Amounts recognized in the consolidated balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: Successor Predecessor 2016 2015 (in millions) (in millions) Other regulatory assets, deferred $ 52 $ 30 Employee benefit obligations (203 ) (219 ) Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is immaterial. Prior Service Cost Net (Gain) Loss (in millions) Successor – Balance at December 31, 2016: Accumulated OCI $ — $ (3 ) Regulatory assets (liabilities) (12 ) 64 Total $ (12 ) $ 61 Predecessor – Balance at December 31, 2015: Accumulated OCI $ — $ 36 Regulatory assets (liabilities) (15 ) 45 Total $ (15 ) $ 81 The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2014: $ 36 $ 39 Net (gain) loss 2 (8 ) Reclassification adjustments: Amortization of prior service costs — 2 Amortization of net loss (2 ) (3 ) Total reclassification adjustments (2 ) (1 ) Total change — (9 ) Predecessor – Balance at December 31, 2015: $ 36 $ 30 Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss (1 ) (1 ) Total reclassification adjustments (1 ) — Total change (1 ) — Predecessor – Balance at June 30, 2016: $ 35 $ 30 Successor – Balance at July 1, 2016: $ — $ 77 Net (gain) loss (3 ) (23 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (3 ) Total reclassification adjustments — (2 ) Total change (3 ) (25 ) Successor – Balance at December 31, 2016: $ (3 ) $ 52 Components of the other postretirement benefit plans' net periodic cost for the periods presented were as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 (in millions) (in millions) Service cost $ 1 $ 1 $ 2 $ 2 Interest cost 5 5 13 15 Expected return on plan assets (3 ) (3 ) (7 ) (7 ) Amortization of regulatory assets 2 — — — Amortization: Prior service costs — (1 ) (3 ) (3 ) Net (gain)/loss — 2 6 6 Net periodic postretirement benefit cost $ 5 $ 4 $ 11 $ 13 Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 20 2018 20 2019 21 2020 22 2021 22 2022 to 2026 111 Benefit Plan Assets Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The assets of the AGL Resources Inc. Retirement Plan (AGL plan) were allocated 69% equity, 20% fixed income, 1% cash, and 10% other at December 31, 2016 compared to the Company's targets of 53% equity, 15% fixed income, 2% cash, and 30% other. The investment policy provides for variation around the target asset allocation in the form of ranges. The assets of the Company's other postretirement benefit plan were allocated 74% equity, 23% fixed income, 1% cash, and 2% other at December 31, 2016 compared to the Company's targets of 72% equity, 24% fixed income, 1% cash, and 3% other. The investment policy provides for variation around the target asset allocation in the form of ranges. The assets of the AGL plan and the Company's other postretirement benefit plan were each allocated 72% equity and 28% fixed income at December 31, 2015 compared to the Company's targets of 70% to 95% equity, 5% to 20% fixed income, and up to 10% cash. The investment policies provided for some variation in these targets in the form of ranges around the target. The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program for its pension plan assets. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for the successor period for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. The investment strategies for the predecessor periods followed a policy to preserve the plans' capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans' assets were managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification. In developing the allocation policy for the assets of the pension and other postretirement benefit plans, the Company examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, the risk and return trade-offs of alternative asset classes and asset mixes were evaluated given long-term historical relationships as well as prospective capital market returns. The Company also conducted asset-liability studies to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. Asset mix guidelines were developed by incorporating the results of these analyses with an assessment of the Company's risk posture, and taking into account industry practices. The Company periodically evaluated its investment strategy to ensure that plan assets were sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, the Company made changes to its targeted asset allocations and investment strategy. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2016 and 2015 . The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation for the successor period, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the 2016 tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation for the predecessor periods, 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. The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Successor – As of December 31, 2016 (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Predecessor – As of December 31, 2015 Pension plans (a) In millions Level 1 Level 2 Level 3 Total % of total Cash $ 4 $ — $ — $ 4 — % Equity securities: U.S. large cap (b) $ 75 $ 199 $ — $ 274 32 % U.S. small cap (b) 57 24 — 81 9 % International companies (c) — 125 — 125 15 % Emerging markets (d) — 28 — 28 3 % Total equity securities $ 132 $ 376 $ — $ 508 59 % Fixed income securities: Corporate bonds (e) $ — $ 91 $ — $ 91 11 % Other (or gov't/muni bonds) — 151 — 151 18 % Total fixed income securities $ — $ 242 $ — $ 242 29 % Other types of investments: Global hedged equity (f) $ — $ — $ 40 $ 40 5 % Absolute return (g) — — 42 42 5 % Private capital (h) — — 20 20 2 % Total other investments $ — $ — $ 102 $ 102 12 % Total assets at fair value $ 136 $ 618 $ 102 $ 856 100 % % of fair value hierarchy 16 % 72 % 12 % 100 % (a) Includes $9 million at December 31, 2015 of medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the other retirement benefits. (b) Includes funds that invest primarily in U.S. common stocks. (c) Includes funds that invest primarily in foreign equity and equity-related securities. (d) Includes funds that invest primarily in common stocks of emerging markets. (e) Includes funds that invest primarily in investment grade debt and fixed income securities. (f) Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or "hedge funds." (g) Includes funds that invest primarily in investment vehicles and commodity pools as a "fund of funds." (h) Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans. The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Successor – As of December 31, 2016 (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Predecessor – As of December 31, 2015 Welfare plans In millions Level 1 Level 2 Level 3 Total % of total Cash $ 1 $ — $ — $ 1 1 % Equity securities: U.S. large cap (a) $ — $ 52 $ — $ 52 58 % U.S. small cap (a) — — — — — % International companies (b) — 15 — 15 17 % Emerging markets (c) — — — — — % Total equity securities $ — $ 67 $ — $ 67 75 % Fixed income securities: Corporate bonds (d) $ — $ 22 $ — $ 22 24 % Other (or gov't/muni bonds) — — — — — % Total fixed income securities $ — $ 22 $ — $ 22 24 % Other types of investments: Global hedged equity (e) $ — $ — $ — $ — — % Absolute return (f) — — — — — % Private capital (g) — — — — — % Total other investments $ — $ — $ — $ — — % Total assets at fair value $ 1 $ 89 $ — $ 90 100 % % of fair value hierarchy 1 % 99 % — % 100 % (a) Includes funds that invest primarily in U.S. common stocks. (b) Includes funds that invest primarily in foreign equity and equity-related securities. (c) Includes funds that invest primarily in common stocks of emerging markets. (d) Includes funds that invest primarily in investment grade debt and fixed income securities. (e) Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or "hedge funds." (f) Includes funds that invest primarily in investment vehicles and commodity pools as a "fund of funds." (g) Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans. Employee Savings Plan SCS sponsors 401(k) defined contribution plans covering certain eligible Southern Company Gas employees. The AGL Resources Inc. 401(k) plans provide matching contributions of either 65% on up to 8% of an employee's eligible compensation, or a 100% matching contribution on up to 3% of an employee's eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee's eligible compensation. Total matching contributions made to the AGL Resources Inc. 401(k) plans for the successor period ended December 31, 2016 were $8 million and for the predecessor periods ended June 30, 2016 and December 31, 2015 and 2014 were $10 million , $16 million , and $14 million , respectively. For employees not accruing a benefit under the AGL Resources Inc. Retirement Plan, additional contributions made to the 401(k) plans for the successor period ended December 31, 2016 were not material and for the predecessor periods ended June 30, 2016 and December 31, 2015 and 2014 were $2 million , $2 million , and $1 million , respectively.

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	12 Months Ended
	Dec. 31, 2016
Loss Contingencies [Line Items]
CONTINGENCIES AND REGULATORY MATTERS	CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. The ultimate outcome of this matter cannot be determined at this time. On January 20, 2017, a purported securities class action complaint was filed against Southern Company and certain of its and Mississippi Power's officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company and certain of its and Mississippi Power's officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time. Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as 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. 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 electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida, have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. Georgia Power's environmental remediation liability as of December 31, 2016 was $17 million . Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $44 million as of December 31, 2016 . These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income. Southern Company Gas' environmental remediation liability as of December 31, 2016 was $426 million based on the estimated cost of environmental investigation and remediation associated with known current and former operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs. In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million . On January 26, 2017, the EPA notified Nicor Gas that it agreed to voluntarily dismiss its administrative complaint with prejudice and without payment of a civil penalty or other further obligation on the part of Nicor Gas. The ultimate outcome of these matters cannot be determined at this time; however, the final disposition of these matters is not expected to have a material impact on Southern Company's financial statements. Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract. In 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In March 2015, Georgia Power recovered approximately $18 million , based on its ownership interests, which was credited to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. Also in March 2015, Alabama Power recovered approximately $26 million , which was applied to reduce the cost of service for the benefit of customers. In 2014, Alabama Power and Georgia Power filed 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, 2016 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 Market-Based Rate Authority The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The traditional electric operating companies and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Southern Company Gas At December 31, 2016, Southern Company Gas' gas midstream operations was involved in three gas pipeline construction projects with expected capital expenditures of approximately $780 million . These projects, along with Southern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. One of these projects received FERC approval in August 2016. The remaining projects are pending FERC approval, which is expected to occur in 2017. The ultimate outcome of this matter cannot be determined at this time. Regulatory Matters Alabama Power Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07% , to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two -year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0% . If Alabama Power's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. On December 1, 2016, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2017. The Rate RSE adjustment was an increase of 4.48% , or $245 million annually, effective January 1, 2017 and includes the performance based adder of 0.07% . Under the terms of Rate RSE, the maximum increase for 2018 cannot exceed 3.52% . As of December 31, 2016, the 2016 retail return exceeded the allowed WCE range; therefore, Alabama Power established a $73 million Rate RSE refund liability. In accordance with an order issued on February 14, 2017 by the Alabama PSC, Alabama Power was directed to apply the full amount of the refund to reduce the under recovered balance of Rate CNP PPA. Rate CNP PPA 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 8, 2016, 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, 2016 through March 31, 2017. No adjustment to Rate CNP PPA is expected in 2017. As of December 31, 2016 and 2015, Alabama Power had an under recovered certificated PPA balance of $142 million and $99 million , respectively, which is included in other regulatory assets, deferred in the balance sheet. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power was authorized to eliminate the under recovered balance in Rate CNP PPA at December 31, 2016 , which totaled approximately $142 million . As discussed herein under "Rate RSE," Alabama Power will utilize the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and will reclassify the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next three to five years . Alabama Power's current depreciation study became effective January 1, 2017. Rate CNP Compliance Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in compliance related operations and maintenance expenses and depreciation generally will have no effect on net income. On December 6, 2016, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2017 the factors associated with Alabama Power's compliance costs for the year 2016. As stated in the consent order, any under-collected amount for prior years will be deemed recovered before the recovery of any current year amounts. Any under recovered amounts associated with 2017 will be reflected in the 2018 filing. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power is authorized to classify any under recovered balance in Rate CNP Compliance up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next three to five years . Alabama Power's current depreciation study became effective January 1, 2017. 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 2015, the Alabama PSC issued a consent order that Alabama Power decrease the Rate ECR factor from 2.681 cents per KWH to 2.030 cents per KWH. On December 6, 2016, the Alabama PSC approved a decrease in Alabama Power's Rate ECR factor from 2.030 to 2.015 cents per KWH, equal to 0.15% , or $8 million annually, based upon projected billings, effective January 1, 2017. The rate will return to 5.910 cents per KWH in 2018 absent a further order from the Alabama PSC. At December 31, 2016 and 2015, Alabama Power's over recovered fuel costs totaled $76 million and $238 million , respectively, and are included in other regulatory liabilities, current. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power is authorized to classify any under recovered balance in Rate ECR up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next three to five years . Alabama Power's current depreciation study became effective January 1, 2017. 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. No such accruals were recorded or designated in any period presented. 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. In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 ( 300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively. In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements. Georgia Power Rate Plans Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60 / 40 basis with their respective customers; thereafter, all merger savings will be retained by customers. In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2015 and 2016 as follows: (1) traditional base tariff rates by approximately $107 million and $49 million , respectively; (2) Environmental Compliance Cost Recovery tariff by approximately $23 million and $75 million , respectively; (3) Demand-Side Management tariffs by approximately $3 million in each year; and (4) Municipal Franchise Fee tariff by approximately $3 million and $13 million , respectively, for a total increase in base revenues of approximately $136 million and $140 million , respectively. 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 refunded 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. In 2016, Georgia Power's retail ROE exceeded 12.00% , and Georgia Power expects to refund to retail customers approximately $40 million , subject to review and approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. Integrated Resource Plan On July 28, 2016, the Georgia PSC approved the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B ( 217 MWs) and Plant Kraft Unit 1 ( 17 MWs), as well as the decertification of the Intercession City unit ( 143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC. Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4. The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case. The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program. The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear as an option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In December 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. On May 17, 2016, the Georgia PSC approved Georgia Power's request to further lower annual billings by approximately $313 million effective June 1, 2016. On December 6, 2016, the Georgia PSC approved the delay of Georgia Power's next fuel case, which was previously scheduled to be filed by February 28, 2017. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. 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 recovered fuel balance exceeds $200 million . Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48 -month time horizon effective January 1, 2016. Georgia Power's over recovered fuel balance totaled approximately $84 million at December 31, 2016 and is included in over recovered regulatory clause revenues, current. At December 31, 2015 , Georgia Power's over recovered fuel balance totaled approximately $116 million , including $10 million in over recovered regulatory clause revenues, current and $106 million in other deferred credits and liabilities. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. Storm Damage Recovery As of December 31, 2016 , the balance in Georgia Power's regulatory asset related to storm damage was $206 million . During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. As of December 31, 2016, Georgia Power had recorded incremental restoration cost related to this hurricane of $121 million , of which approximately $116 million was charged to the storm damage reserve and the remainder was capitalized. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operations and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's 2019 base rate case. As a result of this regulatory treatment, costs related to storms are 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 and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC) (Westinghouse and WECTEC, 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 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 an aggregate cap of 10% of the co
Southern Company Gas [Member]
Loss Contingencies [Line Items]
CONTINGENCIES AND REGULATORY MATTERS	CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of the Company, and Nicor Inc. are defendants in a putative class action initially filed in 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and the Company's motion for summary judgment. The ultimate outcome of this matter cannot be determined at this time. The Company is assessing its alleged involvement in an incident that occurred in one of its service territories that resulted in several deaths, injuries, and property damage. One of the Company's utilities has been named as one of the defendants in several lawsuits related to this incident. The Company has insurance that provides full coverage of any financial exposure in excess of $11 million that is related to this incident. During the successor period ended December 31, 2016 and the predecessor period ended December 31, 2015 , the Company recorded reserves for substantially all of its potential exposure from these cases. The ultimate outcome of this matter cannot be determined at this time. The Company is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. Environmental Matters The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including the handling and disposal of waste and releases of hazardous substances. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites. The natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. The Company is subject to environmental remediation liabilities associated with 46 former MGP sites in five different states. Accrued environmental remediation costs of $426 million have been recorded in the consolidated balance sheets as of December 31, 2016 , $69 million of which is expected to be incurred over the next 12 months. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies, with the exception of one site representing $5 million of the total accrued remediation costs. In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million . On January 26, 2017, the EPA notified Nicor Gas that it agreed to voluntarily dismiss its administrative complaint with prejudice and without payment of a civil penalty or other further obligation on the part of Nicor Gas. The Company's ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time. In 2014, the Company reached a settlement with an insurance company for environmental claims relating to potential contamination at several MGP sites in New Jersey and North Carolina. The terms of the settlement required the insurance company to pay the Company a total of $77 million in two installments. The Company received a $45 million installment in 2014 and the remaining $32 million in July 2015. The New Jersey BPU approved the use of the insurance proceeds to reduce the regulatory assets associated with environmental remediation costs that otherwise would have been recovered from Elizabethtown Gas customers. FERC Matters At December 31, 2016, gas midstream operations was involved in three gas pipeline construction projects. These projects, along with the Company's existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. One of these projects received FERC approval in August 2016. The remaining projects are pending FERC approval. The ultimate outcome of this matter cannot be determined at this time. Regulatory Matters Regulatory Infrastructure Programs The Company has infrastructure improvement programs at several of its utilities. Descriptions of these programs are as follows: Nicor Gas In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average of 4.0% of base rate revenues. In 2014, the Illinois Commission approved the nine -year regulatory infrastructure program, Investing in Illinois, under which Nicor Gas implemented rates that became effective in March 2015. Atlanta Gas Light Atlanta Gas Light's four -year STRIDE program, which was approved by the Georgia PSC in 2013, is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), and the Integrated Vintage Plastic Replacement Program (i-VPR), and consists of infrastructure development, enhancement, and replacement programs that are used to update and expand distribution systems and LNG facilities, improve system reliability, and meet operational flexibility and growth. STRIDE includes a monthly surcharge on firm customers that was approved by the Georgia PSC to provide recovery of the revenue requirement for the ongoing programs and the PRP. This surcharge began in January 2015 and will continue through 2025. The i-SRP program authorized $445 million of capital spending for projects to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, improve its peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Under i-SRP, Atlanta Gas Light must file an updated 10 -year forecast of infrastructure requirements along with a new construction plan every three years for review and approval by the Georgia PSC. Atlanta Gas Light's most recent plan was approved in 2014. On August 1, 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four -year extension of its i-SRP seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Capital investment associated with this filing for 2017 was included in the Georgia Ratemaking Adjustment Mechanism (GRAM) approved by the Georgia PSC on February 21, 2017. Capital investment in subsequent years under this filing will be included in future annual GRAM filings. See "Base Rate Cases" herein for additional information. The i-CGP program authorized Atlanta Gas Light to spend $91 million on projects to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The i-VPR program, which was approved by the Georgia PSC in 2013, authorized Atlanta Gas Light to spend $275 million to replace 756 miles of aging plastic pipe that was installed primarily in the mid-1960s to the early 1980s. Atlanta Gas Light has identified approximately 3,300 miles of vintage plastic mains in its system that should be considered for potential replacement over the next 15 to 20 years under this program. The orders for the STRIDE programs provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the programs net of any cost savings from the programs. All such amounts will be recovered through a combination of straight-fixed-variable rates and a STRIDE revenue rider surcharge. The regulatory asset represents recoverable incurred costs related to the programs that will be collected in future rates charged to customers through the rate riders. The future expected costs to be recovered through rates related to allowed, but not incurred costs, are recognized in an unrecognized ratemaking amount that is not reflected on the consolidated balance sheets. This allowed cost is primarily the equity return on the capital investment under the program. See "Unrecognized Ratemaking Amounts" herein for additional information. Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operations and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operations and maintenance costs in excess of those included in its current base rates, depreciation, and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference. All components of Atlanta Gas Light's STRIDE program were approved by the Georgia PSC in connection with the new rate adjustment mechanism for Atlanta Gas Light. See "Base Rate Cases" herein for additional information. Elizabethtown Gas Elizabethtown Gas' extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program effective in 2013 allowed for infrastructure investment of $115 million over four years , and is focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a WACC of 6.65% . In conjunction with the general base rate case filed with the New Jersey BPU on September 1, 2016, Elizabethtown Gas requested recovery of the AIR program. See "Base Rate Cases" herein for additional information. In 2014, the New Jersey BPU approved Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that improved Elizabethtown Gas' distribution system's resiliency against coastal storms and floods. Under the plan, Elizabethtown Gas invested $15 million in infrastructure and related facilities and communication planning over a one -year period from August 2014 through September 2015. Effective November 2015, Elizabethtown Gas increased its base rates for investments made under the program. In September 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff (SMART) plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. If approved, the program is expected to be completed by 2027. As currently proposed, costs incurred under the program would be recovered through a rider surcharge over a period of 10 years . The ultimate outcome of these matters cannot be determined at this time. Virginia Natural Gas In 2012, the Virginia Commission approved the Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure replacement program, to be completed over a five -year period. This program includes a maximum allowance for capital expenditures of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. Virginia Natural Gas is recovering these program costs through a rate rider that became effective in 2012. On March 9, 2016, the Virginia Commission approved an extension to the SAVE program to replace more than 200 miles of aging pipeline infrastructure. In accordance with the order approving the program, Virginia Natural Gas may invest up to $30 million in 2016 and up to $35 million annually through 2021. Additionally, Virginia Natural Gas may exceed the allowed program expenditures by up to a total of $5 million , of which $2 million was used in 2016. Florida City Gas In September 2015, the Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program, under which costs incurred for replacing aging pipes will be recovered through a rate rider with annual adjustments and true-ups. Under the program, Florida City Gas is authorized to spend $105 million over a 10 -year period on infrastructure relocation and enhancement projects. Customer Refunds In the third quarter 2016, Elizabethtown Gas provided direct per-customer rate credits totaling $17.5 million to its customers in accordance with the Merger approval from the New Jersey BPU. These rate credits were allocated among Elizabethtown Gas' customer classes based on the base rate revenues reflected in the rates that resulted from its most recent base rate proceeding. In the fourth quarter 2016, Elkton Gas provided direct per-customer rate credits totaling $0.4 million to its customers in accordance with the Merger approval from the Maryland PSC. These rate credits were funded from an increase in the amount paid through Elkton Gas' asset management agreement. PRP Settlement In October 2015, Atlanta Gas Light received a final order from the Georgia PSC, which represented a resolution of all matters previously outstanding before the Georgia PSC, including a final determination of the true-up of allowed unrecovered revenue through December 2014. This order allows Atlanta Gas Light to recover $144 million of the $178 million unrecovered program revenue that was requested in its February 2015 filing. The remaining unrecovered amount related primarily to the previously unrecognized ratemaking amount, and did not have a material impact on the Company's consolidated financial statements. The Company also recognized $1 million of interest expense and $5 million in operations and maintenance expense related to the PRP on the Company's consolidated statements of income for the predecessor year ended December 31, 2015. See "Unrecognized Ratemaking Amounts" herein for additional information. Atlanta Gas Light began recovering $144 million in October 2015 through the monthly PRP surcharge of $0.82 , or approximately $15 million annually, which increased by $0.81 on October 1, 2016. The monthly PRP surcharge is scheduled to increase by another $0.81 on October 1, 2017. As part of the Georgia PSC's approval, this increase will commence earlier with its implementation under GRAM. The PRP surcharge will remain effective until the earlier of the full recovery of the under-recovered amount or December 31, 2025. One of the capital projects under the PRP experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. These mitigation costs will be included in future base rates in 2018. See "Base Rate Cases" herein for additional information on GRAM. Provisions in the order resulted in the recognition of $5 million in operations and maintenance expense for the year ended December 31, 2015 on the Company's consolidated statements of income. Atlanta Gas Light continues to pursue contractual and legal claims against certain third-party contractors and will retain any amounts recorded. The ultimate outcome of this matter cannot be determined at this time. Base Rate Cases On December 5, 2016, Atlanta Gas Light filed a joint stipulation with the staff of the Georgia PSC seeking an annual rate review/adjustment mechanism, GRAM. This new mechanism will adjust rates up or down annually and will not collect revenue through special riders and surcharges for the STRIDE infrastructure programs. Also in this filing, Atlanta Gas Light requested an adjustment in base rates designed to collect an additional $20 million in annual revenues effective March 2017. On February 21, 2017, the Georgia PSC approved the joint stipulation and requested base rate adjustment. On September 1, 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU as required under its AIR program, requesting an increase in annual revenues of $19 million , based on an allowed ROE of 10.25% . The Company expects the New Jersey BPU to issue an order on the filing in the third quarter 2017. On December 13, 2016, Virginia Natural Gas filed a notice of intent with the Virginia Commission as required at least 60 days prior to filing a general base rate case. The ultimate outcome of these matters cannot be determined at this time. Gas Cost Prudence Review In 2014, the Illinois Commission staff and the CUB filed testimony in the Nicor Gas 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services and requesting refunds of $18 million and $22 million , respectively. On February 10, 2016, the administrative law judge issued a proposed order affirming an original order by the Illinois Commission, which was approved by the Illinois Commission on March 23, 2016 and concluded this matter. The Illinois Commission approved the purchase gas adjustments for the years 2004 through 2007 on August 9, 2016 and for the years 2008 and 2009 on August 24, 2016. As a condition of these approvals, Nicor Gas agreed to revise the way in which interest is reflected in the calculations beginning in 2013. The Company does not expect this revision to have a material impact on its consolidated financial statements. The gas cost prudence reviews for years 2010 through 2015 are underway. The ultimate outcome of these matters cannot be determined at this time. energySMART In 2014, the Illinois Commission approved Nicor Gas' energySMART program, which outlines energy efficiency offerings and therm reduction goals with spending of $93 million over a three -year period that began in 2014. On December 7, 2016, new energy legislation was signed in Illinois that extended the current program through December 31, 2017. Unrecognized Ratemaking Amounts The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers. Successor Predecessor December 31, 2016 December 31, 2015 (in millions) (in millions) Atlanta Gas Light $ 110 $ 103 Virginia Natural Gas 11 12 Elizabethtown Gas 6 4 Nicor Gas 2 3 Total $ 129 $ 122
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 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In March 2015, the Company recovered approximately $26 million , which was applied to reduce the cost of service for the benefit of customers. In 2014, the Company filed 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, 2016 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 electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. The traditional electric operating companies (including the Company) and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Retail Regulatory Matters Rate RSE The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07% , to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two -year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0% . If the Company's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. On December 1, 2016, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2017. The Rate RSE adjustment was an increase of 4.48% , or $245 million annually, effective January 1, 2017 and includes the performance based adder of 0.07% . Under the terms of Rate RSE, the maximum increase for 2018 cannot exceed 3.52% . As of December 31, 2016, the 2016 retail return exceeded the allowed WCE range; therefore, the Company established a $73 million Rate RSE refund liability. In accordance with an order issued on February 14, 2017 by the Alabama PSC, the Company was directed to apply the full amount of the refund to reduce the under recovered balance of Rate CNP PPA. Rate CNP PPA 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 8, 2016, 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, 2016 through March 31, 2017. No adjustment to Rate CNP PPA is expected in 2017. As of December 31, 2016 and 2015, the Company had an under recovered certificated PPA balance of $142 million and $99 million , respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company was authorized to eliminate the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million . As discussed herein under "Rate RSE," the Company will utilize the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and will reclassify the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next three to five years . The Company's current depreciation study became effective January 1, 2017. Rate CNP Compliance Rate CNP Compliance allows for the recovery of the Company's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in compliance related operations and maintenance expenses and depreciation generally will have no effect on net income. On December 6, 2016, the Alabama PSC issued a consent order that the Company leave in effect for 2017 the factors associated with the Company's compliance costs for the year 2016. As stated in the consent order, any under-collected amount for prior years will be deemed recovered before the recovery of any current year amounts. Any under recovered amounts associated with 2017 will be reflected in the 2018 filing. As of December 31, 2016, the Company had a deferred under recovered regulatory clause revenues balance of $9 million . In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company is authorized to classify any under recovered balance in Rate CNP Compliance up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next three to five years . The Company's current depreciation study became effective January 1, 2017. 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 2015, the Alabama PSC issued a consent order that the Company decrease the Rate ECR factor from 2.681 cents per KWH to 2.030 cents per KWH. On December 6, 2016, the Alabama PSC approved a decrease in the Company's Rate ECR factor from 2.030 to 2.015 cents per KWH, equal to 0.15% , or $8 million annually, based upon projected billings, effective January 1, 2017. The rate will return to 5.910 cents per KWH in 2018 absent a further order from the Alabama PSC. At December 31, 2016 and 2015, the Company's over recovered fuel costs totaled $76 million and $238 million , respectively, and are included in other regulatory liabilities, current. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company is authorized to classify any under recovered balance in Rate ECR up to approximately $36 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next three to five years . The Company's current depreciation study became effective January 1, 2017. 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. No such accruals were recorded or designated in any period presented. 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. In April 2016, as part of its environmental compliance strategy, the Company ceased using coal at Plant Greene County Units 1 and 2 ( 300 MWs representing the Company's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively. In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on the Company's financial statements. Cost of Removal Accounting Order In accordance with an accounting order issued by the Alabama PSC, in 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 previously deferred were fully amortized in 2014.
Georgia Power [Member]
Loss Contingencies [Line Items]
CONTINGENCIES AND REGULATORY MATTERS	CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters In 2011, plaintiffs filed a putative class action against the Company in the Superior Court of Fulton County, Georgia alleging that the Company's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. On November 16, 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. The Company has filed a petition for writ of certiorari with the Georgia Supreme Court. The Company believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time. The Company is 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's environmental remediation liability as of December 31, 2016 was $17 million . The Company has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. The ultimate outcome of these matters cannot be determined at this time; however, as a result of the Company's regulatory treatment for environmental remediation expenses described in Note 1 under "Environmental Remediation Recovery," these matters are not expected to have a material impact on the Company's financial statements. Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with the Company that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Hatch and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract. In 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In March 2015, the Company recovered approximately $18 million , based on its ownership interests, which was credited to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. In 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, 2016 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 electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. The traditional electric operating companies (including the Company) and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Retail Regulatory Matters Rate Plans Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, the 2013 ARP will continue in effect until December 31, 2019, and the Company will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, the Company and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60 / 40 basis with their respective customers; thereafter, all merger savings will be retained by customers. In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2015 and 2016 as follows: (1) traditional base tariff rates by approximately $107 million and $49 million , respectively; (2) ECCR tariff by approximately $23 million and $75 million , respectively; (3) Demand-Side Management tariffs by approximately $3 million in each year; and (4) Municipal Franchise Fee tariff by approximately $3 million and $13 million , respectively, for a total increase in base revenues of approximately $136 million and $140 million , respectively. 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 refunded 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. In 2016, the Company's retail ROE exceeded 12.00% , and the Company expects to refund to retail customers approximately $40 million , subject to review and approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. Integrated Resource Plan On July 28, 2016, the Georgia PSC approved the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B ( 217 MWs) and Plant Kraft Unit 1 ( 17 MWs) , as well as the decertification of the Intercession City unit ( 143 MWs total capacity) . On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, the Company sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC. Additionally, the Georgia PSC approved the Company's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4. The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in the Company's 2019 base rate case. The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by the Company was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program. The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear as an option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. In December 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. On May 17, 2016, the Georgia PSC approved the Company's request to further lower annual billings by approximately $313 million effective June 1, 2016. On December 6, 2016, the Georgia PSC approved the delay of the Company's next fuel case, which was previously scheduled to be filed by February 28, 2017. The Georgia PSC will review the Company's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless the Company deems it necessary to file a fuel case at an earlier time. 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 recovered fuel balance exceeds $200 million . The Company's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48 -month time horizon effective January 1, 2016. The Company's over recovered fuel balance totaled approximately $84 million at December 31, 2016 and is included in over recovered regulatory clause revenues, current. At December 31, 2015 , the Company's over recovered fuel balance totaled approximately $116 million , including $10 million in over recovered regulatory clause revenues, current and $106 million in other deferred credits and liabilities. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow. Storm Damage Recovery As of December 31, 2016, the balance in the Company's regulatory asset related to storm damage was $206 million . During October 2016, Hurricane Matthew caused significant damage to the Company's transmission and distribution facilities. As of December 31, 2016, the Company had recorded incremental restoration cost related to this hurricane of $121 million , of which approximately $116 million was charged to the storm damage reserve and the remainder was capitalized. The Company is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operations and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in the Company's 2019 base rate case. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on the Company's financial statements. See Note 1 under "Storm Damage Recovery" for additional information regarding the Company's storm damage reserve. 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., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC) (Westinghouse and WECTEC, 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 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 an aggregate cap of 10% of the contract price, or approximately $920 million to $930 million . In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which the Company has not been notified have 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% . 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. Certain obligations of Westinghouse have been guaranteed by Toshiba Corporation (Toshiba), Westinghouse's parent company. In the event of certain credit rating downgrades of Toshiba, Westinghouse is required to provide letters of credit or other credit enhancement. In December 2015, Toshiba experienced credit rating downgrades and Westinghouse provided the Vogtle Owners with $920 million of letters of credit. These letters of credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement. On February 14, 2017, Toshiba announced preliminary earnings results for the period ended December 31, 2016, which included a substantial goodwill impairment charge at Westinghouse attributed to increased cost estimates to complete its U.S. nuclear projects, including Plant Vogtle Units 3 and 4. Toshiba also warned that it will likely be in a negative equity position as a result of the charges. At the same time, Toshiba reaffirmed its commitment to its U.S. nuclear projects with implementation of management changes and increased oversight. An inability or failure by the Contractor to perform its obligations under the Vogtle 3 and 4 Agreement could have a material impact on the construction of Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. 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 the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased significantly, but remains subject to limitations. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion . In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an NCCR tariff of $368 million for 2014, as well as increases to the NCCR tariff of approximately $27 million and $19 million effective January 1, 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. In accordance with the 2009 certification order, the Company requested amendments to the Plant Vogtle Units 3 and 4 certificate in both the February 2013 (eighth VCM) and February 2015 (twelfth VCM) filings, when projected construction capital costs to be borne by the Company increased by 5% above the certified costs and estimated in-service dates were extended. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and the Company. In April 2015, the Georgia PSC recognized that the certified cost and the 2013 Stipulation did not constitute a cost recovery cap and deemed the amendment requested in the February 2015 filing unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. 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 litigation that was pending in the U.S. District Court for the Southern District of Georgia (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 June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; 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 $263 million had been paid as of December 31, 2016 . 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 are reflected in the Company's current in-service forecast of $5.440 billion . Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor and (ii) the Vogtle Owners, Chicago Bridge & Iron Co, N.V., and The Shaw Group Inc. 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 December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above the Company's current forecast of $5.440 billion , (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) the Company would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion . Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be the Company's average cost of long-term debt. If the Georgia PSC adjusts the Company's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be the Company's average cost of long-term debt. Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than the Company's base rate case required to be filed by July 1, 2019. The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion . The Company expects to file the sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC by February 28, 2017. The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.9 billion as of December 31, 2016, and the Company had incurred $1.3 billion in financing costs through December 31, 2016. As of December 31, 2016, the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between the Company and the DOE and a multi-advance credit facility among the Company, the DOE, and the FFB. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, and mandatory prepayment events. 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. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise 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. In addition to Toshiba's reaffirmation of its commitment, the Contractor provided the Company with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. The Company is currently reviewing a preliminary summary schedule supporting these dates that ultimately must be reconciled to a detailed integrated project schedule. As construction continues, the risk remains that challenges with Contractor performance including labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. The Company expects the Contractor to employ mitigation efforts and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. The Company estimates its financing costs for Plant Vogtle Units 3 and 4 to be approximately $30 million per month, with total construction period financing costs of approximately $2.5 billion . Additionally, the Company estimates its owner's costs to be approximately $6 million per month, net of delay liquidated damages. The revised forecasted in-service dates are within the timeframe contemplated in the Vogtle Cost Settlement Agreement and would enable both units to qualify for production tax credits the IRS has allocated to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021. The net present value of the production tax credits is estimated at approximately $400 million per unit. 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, 2016 , the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $44 million , of which approximately $4 million is included in under recovered regulatory clause revenues and other current liabilities and approximately $40 million is included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company's environmental cost recovery clause; therefore, these liabilities have no impact on net income. The ultimate 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 electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. The traditional electric operating companies (including the Company) and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Retail Regulatory Matters The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates. Retail Base Rate Cases In 2013, the Florida PSC approved 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 and $20 million annually effective January 2014 and 2015, respectively; (2) continued its authorized retail ROE midpoint ( 10.25% ) and range ( 9.25% – 11.25% ); and (3) accrued a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 through January 1, 2017. The 2013 Rate Case Settlement Agreement also provides that the Company may reduce depreciation 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 from January 2014 through June 2017. In any given month, such depreciation 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 2016 Rate Case, as defined below. For 2014 and 2015, the Company recognized reductions in depreciation expense of $8.4 million and $20.1 million , respectively. No net reduction in depreciation was recorded in 2016. On October 12, 2016, the Company filed a petition (2016 Rate Case) with the Florida PSC requesting an annual increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25% . The requested increase includes recovery of the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers following the contract expirations at the end of 2015 and May 2016. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, the Company may consider an asset sale. The current book value of the Company's ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. The Company has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time. Cost Recovery Clauses On November 2, 2016, the Florida PSC approved the Company's 2017 annual cost recovery clause rates for its fuel, purchased power capacity, environmental, and energy conservation cost recovery clauses. The net effect of the approved changes is a decrease of approximately $41 million in annual revenues effective in January 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental cost recovery clause rate, which increased annual revenues by approximately $12 million in 2016 and is expected to increase revenues by an incremental $2 million for a total of approximately $14 million in 2017. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC's ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decided in the 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time. 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, 2016 and 2015 , the over recovered fuel balance was approximately $15 million and $18 million , respectively, which is included in other regulatory liabilities, current 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, 2016 and 2015 , 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. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2016 , the over recovered environmental balance of approximately $8 million , along with the current portion of projected environmental expenditures, was included in under recovered regulatory clause revenues in the balance sheet. At December 31, 2015 , the over recovered environmental balance was immaterial. 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, 2016 , the under recovered ECCR balance was approximately $4 million , which is included in under recovered regulatory clause revenues in the balance sheet. 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. Other Matters As a result of the cost to comply with environmental regulations imposed by the EPA, the Company retired its coal-fired generation at Plant Smith Units 1 and 2 ( 357 MWs) on March 31, 2016. The Company filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. On August 29, 2016, the Florida PSC approved the Company's request to reclassify these costs, totaling $63 million , to a regulatory asset for recovery over a period to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time.
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 established regulatory mechanisms. FERC Matters Municipal and Rural Associations Tariff In 2013, the FERC accepted a settlement agreement entered into by the Company with its wholesale customers which approved, among other things, the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC for certain items. The regulatory treatment includes (i) approval to establish a regulatory asset for the portion of non-capitalizable Kemper IGCC-related costs which have been and will continue to be incurred during the construction period for the Kemper IGCC, (ii) authorization to defer as a regulatory asset, for the 10 -year period ending October 2021, the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 (assuming a remaining 30 -year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment with the accumulated deferred balance at the end of the deferral being amortized into wholesale rates over the remaining life of Plant Daniel Units 3 and 4, and (iii) authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. In 2014, the Company reached, and the FERC accepted, a settlement agreement with its wholesale customers for an estimated annual increase in the MRA cost-based tariff of approximately $10 million , effective May 1, 2014. Included in this settlement agreement was a mechanism allowing the Company to adjust the wholesale revenue requirement in a subsequent rate proceeding 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. In May 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, resulting in an estimated annual AFUDC increase of approximately $14 million , of which approximately $11 million is related to the Kemper IGCC. On March 31, 2016, the Company reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in November 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $14 million through the Kemper IGCC's projected in-service date of mid-March 2017. Fuel Cost Recovery The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers. At December 31, 2016 and 2015, the amount of over recovered wholesale MRA fuel costs were approximately $13 million and $24 million , respectively, which is included in over recovered regulatory clause liabilities, current in the balance sheets. Effective January 1, 2017, the wholesale MRA fuel rate increased $10 million annually. The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow. Market-Based Rate Authority The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. The traditional electric operating companies (including the Company) and Southern Power expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time. Retail Regulatory Matters General In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time. Performance Evaluation Plan The Company's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing. In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the 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 the 2010 PEP lookback filing, which remain under review, also impact the 2012 PEP lookback filing. In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9% , or $15 million , annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase. In 2014, 2015, and 2016, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for 2015 indicated a $5 million surcharge. On July 12, 2016 and November 15, 2016, the Company submitted its annual projected PEP filings for 2016 and 2017, respectively, which each indicated no change in rates. The Mississippi PSC suspended each of these filings to allow more time for review. In 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi. The ultimate outcome of these matters cannot be determined at this time. Energy Efficiency In 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were required to be filed within six months of the order and will be in effect for two to three years . On May 3, 2016, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider Compliance filing, which reduced annual retail revenues by approximately $2 million effective with the first billing cycle for June 2016. On November 30, 2016, the Company submitted its Energy Efficiency Cost Rider Compliance filing, which included an increase of $1 million in annual retail revenues. The ultimate outcome of this matter cannot be determined at this time. Environmental Compliance Overview Plan In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In 2014, the Company entered into a settlement agreement with the Sierra Club 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 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 (and the units were retired in July 2016). The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 ( 750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred in April 2015) and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 ( 200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas (which occurred in June and July 2016, respectively). In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. As of December 31, 2016, $17 million of Plant Greene County costs have been reclassified as regulatory assets and are expected to be recovered through the ECO plan and other existing cost recovery mechanisms over a period to be determined by the Mississippi PSC. The Mississippi PSC approved $41 million of costs that were reclassified to a regulatory asset associated with Plant Watson for amortization over a five -year period that began in July 2016. As a result, these decisions are not expected to have a material impact on the Company's financial statements. On August 17, 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million , primarily related to the Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing . On February 14, 2017, the Company submitted its ECO plan filing for 2017, which requested an increase in annual revenues over 2016, capped at 2% of total retail revenues, of approximately $18 million , primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in November 2015. The revenue requirement in excess of the 2% , approximately $27 million plus carrying costs, will be carried forward to the 2018 filing. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. The Mississippi PSC approved the 2016 retail fuel cost recovery factor, effective January 5, 2016, which resulted in an annual revenue decrease of approximately $120 million . On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016. At December 31, 2016 and 2015, over recovered retail fuel costs were approximately $37 million and $71 million , respectively, which is included in over recovered regulatory clause liabilities, current in the balance sheets. On January 12, 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which will result in an annual revenue increase of approximately $55 million . 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 June 17, 2016, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2016, which included an annual rate decrease of 0.07% , or $1 million in annual retail revenues, primarily due to the prior year over recovery. System Restoration Rider In October 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. On February 19, 2016, the filing was suspended by the Mississippi PSC for review. The ultimate outcome of this matter cannot be determined at this time. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed that the rate level remain at zero and the Company be allowed to accrue $4 million annually to the property damage reserve in 2017. The ultimate outcome of this matter cannot be determined at this time. See Note 1 under "Provision for Property Damage" for additional information. Storm Damage Cost Recovery In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order dated January 24, 2017, the Company has adjusted the System Restoration Charge implemented after Hurricane Katrina to zero . Upon completion of the proper defeasance process by the Mississippi State Bond Commission, the Company's obligations in relation to system restoration bonds issued after Hurricane Katrina in 2005 will be completely satisfied. Integrated Coal Gasification Combined Cycle Kemper IGCC Overview The Kemper IGCC utilizes IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC is 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 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 Initial 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 in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. The Company subsequently completed a brief outage to repair and make modifications to further improve the plant's ability to achieve sustained operations sufficient to support placing the plant in service for customers. Efforts to reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines are in process. The plant has produced and captured CO 2 , and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. On February 20, 2017, the Company determined gasifier "B," which has been producing syngas over 60% of the time since early November 2016, requires an outage to remove ash deposits from its ash removal system. Gasifier "A" and combustion turbine "A" are expected to remain in operation, producing electricity from syngas, as well as producing chemical by-products. As a result, the Company currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by mid-March 2017. The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of December 31, 2016, all of which include 100% of the costs for the Kemper IGCC, are as follows: Cost Category 2010 Project Estimate (a) Current Cost Estimate (b) Actual Costs (in billions) Plant Subject to Cost Cap (c)(e) $ 2.40 $ 5.64 $ 5.44 Lignite Mine and Equipment 0.21 0.23 0.23 CO 2 Pipeline Facilities 0.14 0.11 0.11 AFUDC (d) 0.17 0.79 0.75 Combined Cycle and Related Assets Placed in Service – Incremental (e) — 0.04 0.04 General Exceptions 0.05 0.10 0.09 Deferred Costs (e) — 0.22 0.21 Additional DOE Grants (f) — (0.14 ) (0.14 ) Total Kemper IGCC (g) $ 2.97 $ 6.99 $ 6.73 (a) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO 2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. (b) Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. (c) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). 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. (d) The Company's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also 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. (e) Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. (f) On April 8, 2016, the Company received approximately $137 million in Additional DOE Grants, which are expected to be used to reduce future rate impacts for customers. (g) The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 under "Fuel Inventory," Note 6 under "Capital Leases," and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information. Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2016 , $3.67 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.84 billion ), $6 million in other property and investments, $75 million in fossil fuel stock, $47 million in materials and supplies, $29 million in other regulatory assets, current, $172 million in other regulatory assets, deferred, $3 million in other current assets, and $14 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 Initial DOE Grants and excluding the Cost Cap Exceptions. The Company recorded pre-tax charges to income for revisions to the cost estimate of $348 million ( $215 million after tax), $365 million ( $226 million after tax), and $868 million ( $536 million after tax) in 2016, 2015, and 2014, respectively. Since 2012, in the aggregate, the Company has incurred charges of $2.76 billion ( $1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016. The increases to the cost estimate in 2016 primarily reflect $186 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to March 15, 2017 and $162 million for increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to both gasifiers, mechanical improvements to coal feed and ash management systems, and outage work, as well as certain post-in-service costs expected to be subject to the cost cap. In addition to the current construction cost estimate, the Company is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. As of December 31, 2016, approximately $12 million of related potential costs has been included in the estimated loss on the Kemper IGCC. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. Any extension of the in-service date beyond mid-March 2017 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. 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 mid-March 2017 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 $16 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 $3 million per month. For additional information, see "2015 Rate Case" herein. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of income and these changes could be material. Rate Recovery of Kemper IGCC Costs Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on the Company's results of operations, financial condition, and liquidity. As of December 31, 2016, in addition to the $2.76 billion of costs above the Mississippi PSC's $2.88 billion cost cap that have been recognized as a charge to income, the Company had incurred approximately $1.99 billion in costs subject to the cost cap and approximately $1.46 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following: Cost Category Actual Costs (in billions) Gasifiers and Gas Clean-up Facilities $ 1.88 Lignite Mine Facility 0.31 CO 2 Pipeline Facilities 0.11 Combined Cycle and Common Facilities 0.16 AFUDC 0.69 General exceptions 0.07 Plant inventory 0.03 Lignite inventory 0.08 Regulatory and other deferred assets 0.12 Subtotal 3.45 Additional DOE Grants (0.14 ) Total $ 3.31 Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. The Company and its wholesale customers have generally agreed to the similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See "FERC Matters – Municipal and Rural Associations Tariff" and "Termination of Proposed Sale of Undivided Interest" herein for further information. Prudence On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, the Company made a required compliance filing, which included a review and e
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 and certain of its generation subsidiaries are subject to regulation by the FERC. The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. On December 9, 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The traditional electric operating companies and the Company expect to make a compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter. The ultimate outcome of these matters cannot be determined at this time.

Joint Ownership Agreements

Joint Ownership Agreements	12 Months Ended
	Dec. 31, 2016
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: 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. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. At December 31, 2016 , 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 % $ 3,545 $ 2,111 $ 74 Plant Hatch (nuclear) 50.1 1,297 585 81 Plant Miller (coal) Units 1 and 2 91.8 1,657 587 23 Plant Scherer (coal) Units 1 and 2 8.4 258 90 3 Plant Wansley (coal) 53.5 1,046 308 12 Rocky Mountain (pumped storage) 25.4 181 129 — Plant Stanton (combined cycle) Unit A 65.0 155 58 — Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of approximately $3.9 billion as of December 31, 2016. See Note 3 under " 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, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing. Southern Company Gas has a 50% undivided ownership interest with The Williams Companies, Inc. in a 115 -mile pipeline facility being constructed in northwest Georgia. The CWIP balance representing Southern Company Gas' share of construction costs was approximately $124 million as of December 31, 2016 . Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility once it is placed in service, which is currently expected to be later in 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years . The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.
Alabama Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. 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 $55 million in 2016 , $76 million in 2015 , and $84 million in 2014 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, 2016 , the capitalization of SEGCO consisted of $108 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 $38 million . SEGCO paid $24 million of dividends in 2016 compared to an immaterial amount in 2015 and 2014 , 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 became 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 an associated gas pipeline. The Company owns 14% of the pipeline with the remaining 86% owned by SEGCO. In addition to the Company's ownership of SEGCO and joint ownership of an associated gas pipeline, the Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2016 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) $ 168 $ 66 $ 1 Plant Miller Units 1 and 2 1,320 91.84 % (2) 1,657 587 23 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth Energy Cooperative, Inc. The Company has contracted to operate and maintain its jointly-owned facilities as agent for their co-owners. The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the Company is responsible for providing its own financing.
Georgia Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. 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 $57 million in 2016 , $78 million in 2015 , and $84 million in 2014 and is included in purchased power, affiliates in the statements of income. The Company accounts for SEGCO using the equity method. See Note 7 under "Guarantees" for additional information. The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: 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, which is the operator of the plant. On August 31, 2016, the Company sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. At December 31, 2016 , 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 % $ 3,545 $ 2,111 $ 74 Plant Hatch (nuclear) 50.1 1,297 585 81 Plant Wansley (coal) 53.5 1,046 308 12 Plant Scherer (coal) Units 1 and 2 8.4 258 90 3 Unit 3 75.0 1,203 458 23 Rocky Mountain (pumped storage) 25.4 181 129 — The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing. The Company also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of approximately $3.9 billion as of December 31, 2016. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information.
Gulf Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units. The Company and Georgia Power jointly own the 818 -MW capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit. At December 31, 2016 , 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 $ 398 $ 680 Accumulated depreciation 143 202 Construction work in progress 7 7 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]
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company. At December 31, 2016 , 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 % $ 165 $ 48 $ — Daniel Units 1 and 2 50 % $ 695 $ 173 $ 15 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]
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS The Company is a 65% owner of Plant Stanton A, a natural gas-fired combined-cycle unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission ( 28% ), the Florida Municipal Power Agency ( 3.5% ), and the Kissimmee Utility Authority ( 3.5% ). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2016 , $155 million was recorded in plant in service with associated accumulated depreciation of $58 million . These amounts represent the Company's share of total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the consolidated statements of income.
Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
JOINT OWNERSHIP AGREEMENTS	JOINT OWNERSHIP AGREEMENTS In 2014, the Company entered into two arrangements associated with the Dalton Pipeline. The first was a construction and ownership agreement through which the Company has a 50% undivided ownership interest jointly with The Williams Companies, Inc. in the 115 -mile Dalton Pipeline that is being constructed to serve as an extension of the Transco natural gas pipeline system into northwest Georgia. The Company also entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline once it is placed in service. Under the lease, the Company will receive approximately $26 million annually for an initial term of 25 years . The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Engineering design work is complete and construction began in September 2016. At December 31, 2016 and December 31, 2015 , the Company's 50% share of construction costs was $124 million and $33 million , respectively, and is reflected in construction work in progress in the consolidated balance sheets. Variable Interest Entities SouthStar, previously a joint venture owned 85% by the Company and 15% by Piedmont, was the only VIE for which the Company was the primary beneficiary, prior to October 3, 2016 when the Company completed its purchase of Piedmont's remaining interest in SouthStar. In December 2015, Georgia Natural Gas Company (GNG), a 100% -owned, direct subsidiary of the Company, notified Piedmont of its election, pursuant to a change in control of SouthStar, to purchase Piedmont's 15% interest in SouthStar at fair market value. This purchase was contingent upon the closing of the merger between Piedmont and Duke Energy Corporation (Duke Energy). On February 12, 2016, GNG and Piedmont entered into a letter agreement pursuant to which GNG agreed to pay Piedmont $160 million as the fair value for Piedmont's entire ownership interest in SouthStar. After Piedmont and Duke Energy completed their merger in October 2016, GNG completed its purchase of Piedmont's interest in SouthStar on October 3, 2016 and paid a purchase price of $160 million and $15 million for Piedmont's share of SouthStar's 2016 earnings through the date of acquisition. At December 31, 2015, the Company presented the noncontrolling interest related to Piedmont's interest in SouthStar as a component in equity. During the first quarter 2016, the Company reclassified its noncontrolling interest, whose redemption was beyond the Company's control, as a contingently redeemable noncontrolling interest. Upon Piedmont and Duke Energy obtaining the necessary merger approval, the Company deemed this noncontrolling interest to be mandatorily redeemable and reclassified it to a current liability during the third quarter 2016. The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below: Predecessor – (in millions) Balance at December 31, 2015 $ — Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest 46 Net income attributable to noncontrolling interest 14 Distribution to noncontrolling interest (19 ) Balance at June 30, 2016 $ 41 Successor – (in millions) Balance at July 1, 2016 $ 174 Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable (174 ) Balance at December 31, 2016 $ — The Company's cash flows used for financing activities include SouthStar's distribution to Piedmont for its portion of SouthStar's annual earnings from the previous year, which generally occurred in the first quarter of each year. For the successor period of July 1, 2016 through December 31, 2016 , SouthStar made a distribution of $15 million upon completion of the purchase of Piedmont's interest in SouthStar. For the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , SouthStar distributed to Piedmont $19 million , $18 million , and $17 million , respectively. Equity Method Investments The carrying amounts of the Company's equity method investments as of December 31, 2016 and 2015 and related income from those investments for the successor period ended December 31, 2016 and predecessor periods ended June 30, 2016 and December 31, 2015 and 2014 were as follows: Balance Sheet Information Successor Predecessor December 31, 2016 December 31, 2015 (in millions) (in millions) SNG $ 1,394 $ — Triton 44 49 Horizon Pipeline 30 14 PennEast Pipeline 22 9 Atlantic Coast Pipeline 33 7 Pivotal JAX LNG, LLC 16 — Other 2 1 Total $ 1,541 $ 80 Income Statement Information Successor Predecessor July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 2015 2014 (in millions) (in millions) SNG $ 56 $ — $ — $ — Triton 2 1 4 6 Horizon Pipeline 1 1 2 2 Atlantic Coast Pipeline 1 — — — Total $ 60 $ 2 $ 6 $ 8 SNG On September 1, 2016, the Company, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. See Note 11 under "Investment in SNG" for additional information on this investment. Selected financial information of SNG since the Company's September 1, 2016 acquisition of a 50% equity interest is as follows: Balance Sheet Information As of December 31, 2016 (in millions) Current assets $ 95 Property, plant, and equipment 2,451 Deferred charges and other assets 129 Total Assets $ 2,675 Current liabilities $ 588 Long-term debt 706 Other deferred charges and other liabilities 22 Total Liabilities $ 1,316 Total Stockholders' Equity 1,359 Total Liabilities and Stockholders' Equity $ 2,675 Income Statement Information September 1, 2016 (in millions) Revenues $ 230 Operating income $ 138 Net income $ 115 Other Investments Triton The Company has an investment in Triton, a cargo container leasing company, which is aggregated into its all other segment. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton's operating agreement and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2016 , the Company had invested in seven tranches established by Triton. Horizon Pipeline The Company owns an interest in a joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC. Horizon Pipeline operates a 70 -mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total annual capacity. PennEast Pipeline In 2014, the Company entered into a partnership in which it holds a 20% ownership interest in an interstate pipeline company formed to develop and operate a 118 -mile natural gas pipeline between New Jersey and Pennsylvania. The initial transportation capacity of 1.0 billion cubic feet (Bcf) per day, is under long-term contracts, mainly by public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York. Atlantic Coast Pipeline In 2014, the Company entered into a project in which it holds a 5% ownership interest in an interstate pipeline company formed to develop and operate a 594 -mile natural gas pipeline in North Carolina, Virginia, and West Virginia with initial transportation capacity of 1.5 Bcf per day. Pivotal JAX LNG, LLC The Company owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida. Once construction is complete and the facility is operational, it will be outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Line Items]
INCOME TAXES	INCOME TAXES Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal — Current $ 1,184 $ (177 ) $ 175 Deferred (342 ) 1,266 695 842 1,089 870 State — Current (108 ) (33 ) 93 Deferred 217 138 14 109 105 107 Total $ 951 $ 1,194 $ 977 Net cash payments (refunds) for income taxes in 2016 , 2015 , and 2014 were $(148) million , $(9) million , and $272 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: 2016 2015 (in millions) Deferred tax liabilities — Accelerated depreciation $ 15,392 $ 12,767 Property basis differences 2,708 1,603 Leveraged lease basis differences 314 308 Employee benefit obligations 737 579 Premium on reacquired debt 89 95 Regulatory assets associated with employee benefit obligations 1,584 1,378 Regulatory assets associated with AROs 1,781 1,422 Other 907 793 Total 23,512 18,945 Deferred tax assets — Federal effect of state deferred taxes 597 479 Employee benefit obligations 1,868 1,720 Over recovered fuel clause 66 104 Other property basis differences 401 695 Deferred costs 100 83 ITC carryforward 1,974 770 Federal NOL carryforward 1,084 38 Unbilled revenue 92 111 Other comprehensive losses 152 85 AROs 1,732 1,482 Estimated Loss on Kemper IGCC 484 451 Deferred state tax assets 266 222 Other 679 443 Total 9,495 6,683 Valuation allowance (23 ) (4 ) Total deferred income taxes 14,040 12,266 Portion included in accumulated deferred tax assets (52 ) (56 ) Accumulated deferred income taxes $ 14,092 $ 12,322 The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation. At December 31, 2016 , 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, 2016 , the tax-related regulatory liabilities to be credited to customers were $219 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 electric 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 $22 million in 2016 , $21 million in 2015 , and $22 million in 2014 . 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 $37 million in 2016 , $19 million in 2015 , and $11 million in 2014 . Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million and $74 million for the years ended December 31, 2015 and 2014 , respectively. No cash was received related to these incentives in 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $173 million in 2016 , $54 million in 2015 , and $48 million in 2014 . See " Unrecognized Tax Benefits " below for further information. Tax Credit Carryforwards At December 31, 2016 , Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $1.8 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be fully utilized by 2022. The acquisition of additional renewable projects and carrying back the federal NOL, as well as potential tax reform legislation on existing renewable incentives, could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time. Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling $202 million , which begin expiring in 2020 but are expected to be fully utilized. Net Operating Loss At December 31, 2016, Southern Company had a consolidated federal NOL carryforward of $3 billion , of which $2.8 billion is projected for the 2016 tax year. The federal NOL will begin expiring in 2033. However, portions of the NOL are expected to be carried back to prior tax years and forward to future tax years. The ultimate outcome of this matter cannot be determined at this time. At December 31, 2016, the state NOL carryforwards for Southern Company's subsidiaries were as follows: Jurisdiction NOL Carryforwards Net State Income Tax Benefit Tax Year NOL Begins Expiring (in millions) Mississippi $ 3,448 $ 112 2032 Oklahoma 839 31 2036 Georgia 685 25 2019 New York 229 11 2036 New York City 209 12 2036 Florida 198 7 2034 Other states 146 5 Various Total $ 5,754 $ 203 Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 2.1 1.9 2.3 Employee stock plans dividend deduction (1.2 ) (1.2 ) (1.4 ) Non-deductible book depreciation 0.9 1.2 1.4 AFUDC-Equity (2.0 ) (2.2 ) (2.9 ) ITC basis difference (5.0 ) (1.5 ) (1.6 ) Federal PTCs (1.2 ) — — Amortization of ITC (0.9 ) (0.5 ) (0.5 ) Other (0.4 ) 0.2 0.2 Effective income tax rate 27.3 % 32.9 % 32.5 % Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs. On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company's overall effective tax rate. See Note 1 under " Recently Issued Accounting Standards " for additional information. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2016 2015 2014 (in millions) Unrecognized tax benefits at beginning of year $ 433 $ 170 $ 7 Tax positions increase from current periods 45 43 64 Tax positions increase from prior periods 21 240 102 Tax positions decrease from prior periods (15 ) (20 ) (3 ) Balance at end of year $ 484 $ 433 $ 170 The tax positions increase from current and prior periods for 2016 and 2015 relate primarily to deductions for R&E expenditures associated with the Kemper IGCC and federal income tax benefits from deferred ITCs. 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 2016 and 2015 relates to federal income tax benefits from deferred ITCs. The impact on Southern Company's effective tax rate, if recognized, is as follows: 2016 2015 2014 (in millions) Tax positions impacting the effective tax rate $ 20 $ 10 $ 10 Tax positions not impacting the effective tax rate 464 423 160 Balance of unrecognized tax benefits $ 484 $ 433 $ 170 The tax positions impacting the effective tax rate primarily relate to federal deferred income tax credits and Southern Company's estimate of the uncertainty related to the amount of those benefits. If these tax positions are not able to be recognized due to a federal audit adjustment in the amount that has been estimated, the amount of tax credit carryforwards discussed above would be reduced by approximately $92 million . The tax positions not impacting the effective tax rate for 2016 , 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 all tax positions other than the Section 174 R&E deductions was immaterial for all years presented. Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months . The settlement of federal and state audits and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See " Section 174 Research and Experimental Deduction " herein for more information. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014 , and 2015 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 reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. 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. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest of $28 million as of December 31, 2016 . This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time. See Note 3 under " Integrated Coal Gasification Combined Cycle " for additional information regarding the Kemper IGCC.
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: 2016 2015 2014 (in millions) Federal — Current $ 103 $ 110 $ 198 Deferred 339 320 225 442 430 423 State — Current 20 8 44 Deferred 69 68 45 89 76 89 Total $ 531 $ 506 $ 512 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: 2016 2015 (in millions) Deferred tax liabilities — Accelerated depreciation $ 4,307 $ 3,917 Property basis differences 456 456 Premium on reacquired debt 26 28 Employee benefit obligations 201 200 Regulatory assets associated with employee benefit obligations 393 375 Asset retirement obligations 289 289 Regulatory assets associated with asset retirement obligations 347 312 Other 179 175 Total 6,198 5,752 Deferred tax assets — Federal effect of state deferred taxes 266 242 Unbilled fuel revenue 36 39 Storm reserve 21 23 Employee benefit obligations 427 407 Other comprehensive losses 19 20 Asset retirement obligations 636 600 Other 139 180 Total 1,544 1,511 Accumulated deferred income taxes, net $ 4,654 $ 4,241 The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation in 2016 and 2015. At December 31, 2016 , the tax-related regulatory assets to be recovered from customers were $526 million . These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. At December 31, 2016 , the tax-related regulatory liabilities to be credited to customers were $65 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 annually in 2016, 2015, and 2014. At December 31, 2016 , 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: 2016 2015 2014 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.2 3.8 4.4 Non-deductible book depreciation 1.0 1.2 1.1 AFUDC equity (0.7) (1.6) (1.3) Other (0.7) — (0.2) Effective income tax rate 38.8% 38.4% 39.0% On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under " Recently Issued Accounting Standards " for additional information. Unrecognized Tax Benefits The Company has no material unrecognized tax benefits for the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and the Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 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: 2016 2015 2014 (in millions) Federal – Current $ 391 $ 515 $ 295 Deferred 319 176 366 710 691 661 State – Current 6 81 82 Deferred 64 (3 ) (14 ) 70 78 68 Total $ 780 $ 769 $ 729 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: 2016 2015 (in millions) Deferred tax liabilities – Accelerated depreciation $ 5,266 $ 4,909 Property basis differences 957 1,003 Employee benefit obligations 428 310 Premium on reacquired debt 56 61 Regulatory assets – Storm damage reserves 83 37 Employee benefit obligations 546 528 Asset retirement obligations 726 545 Retired assets 55 58 Asset retirement obligations 182 161 Other 83 92 Total 8,382 7,704 Deferred tax assets – Federal effect of state deferred taxes 173 150 Employee benefit obligations 661 642 Other property basis differences 105 88 Other deferred costs 100 83 State investment tax credit carryforward 201 216 Federal tax credit carryforward 84 3 Unbilled fuel revenue 47 47 Regulatory liabilities associated with asset retirement obligations 33 60 Asset retirement obligations 908 706 Other 70 82 Total 2,382 2,077 Accumulated deferred income taxes $ 6,000 $ 5,627 The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation in 2016 and 2015. At December 31, 2016 , tax-related regulatory assets to be recovered from customers were $681 million . These assets are primarily attributable to tax benefits flowed through to customers in prior years and deferred taxes previously recognized at rates lower than the current enacted tax law. At December 31, 2016 , tax-related regulatory liabilities to be credited to customers were $121 million . These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law. In accordance with regulatory requirements, utilized federal ITCs are deferred and amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $10 million in each of 2016 , 2015 , and 2014 . State investment tax credits are recognized in the period in which the credits are generated and totaled $42 million in 2016 , $33 million in 2015 , and $34 million in 2014 . At December 31, 2016 , the Company had $83 million in federal ITC carryforwards that will expire by 2036 and $201 million in state ITC carryforwards that will expire between 2019 and 2027. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 2.1 2.5 2.2 Non-deductible book depreciation 0.8 1.2 1.3 AFUDC equity (0.8 ) (0.7 ) (0.8 ) Other (0.4 ) (0.4 ) (0.7 ) Effective income tax rate 36.7 % 37.6 % 37.0 % On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits The Company had no unrecognized tax benefits as of December 31, 2016 and no material changes in unrecognized tax benefits for any year presented. The Company classifies interest on tax uncertainties as interest expense; however, the Company did not have any accrued interest or penalties for unrecognized tax benefits for any year presented. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 through 2015 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: 2016 2015 2014 (in millions) Federal - Current $ 34 $ (3 ) $ 23 Deferred 45 80 52 79 77 75 State - Current — 5 — Deferred 12 10 13 12 15 13 Total $ 91 $ 92 $ 88 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: 2016 2015 (in millions) Deferred tax liabilities- Accelerated depreciation $ 834 $ 812 Property basis differences 123 133 Pension and other employee benefits 58 39 Regulatory assets 45 16 Regulatory assets associated with employee benefit obligations 65 59 Regulatory assets associated with asset retirement obligations 55 40 Other 12 10 Total 1,192 1,109 Deferred tax assets- Federal effect of state deferred taxes 37 33 Postretirement benefits 26 26 Pension and other employee benefits 72 65 Property reserve 17 15 Asset retirement obligations 55 40 Alternative minimum tax carryforward 18 18 Other 19 19 Total 244 216 Accumulated deferred income taxes $ 948 $ 893 The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation in 2016 and 2015. At December 31, 2016 , tax-related regulatory assets to be recovered from customers were $58 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, 2016 , the tax-related regulatory liabilities to be credited to customers were $2 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 are not material for the periods presented. At December 31, 2016 , 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: 2016 2015 2014 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.9 3.5 Non-deductible book depreciation 0.6 0.5 0.4 Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.1) AFUDC equity — (1.8) (1.8) Other, net 0.6 (0.6) 0.1 Effective income tax rate 39.5% 36.9% 37.1% The increase in the Company's 2016 effective tax rate is primarily the result of the decrease in nontaxable AFUDC equity. On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits The Company has no material unrecognized tax benefits for the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and the Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months . The settlement of federal and state audits could impact the balances, but an estimate of the range of reasonably possible outcomes cannot be determined at this time. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 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: 2016 2015 2014 (in millions) Federal — Current $ (31 ) $ (768 ) $ (431 ) Deferred (60 ) 704 183 (91 ) (64 ) (248 ) State — Current (6 ) (81 ) 1 Deferred (7 ) 73 (38 ) (13 ) (8 ) (37 ) Total $ (104 ) $ (72 ) $ (285 ) 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: 2016 2015 (in millions) Deferred tax liabilities — Accelerated depreciation $ 386 $ 1,618 Property basis difference 852 — Regulatory assets associated with AROs 72 71 Pensions and other benefits 49 30 Regulatory assets associated with employee benefit obligations 70 66 Regulatory assets associated with the Kemper IGCC 82 86 Rate differential 144 115 Other 125 176 Total 1,780 2,162 Deferred tax assets — Fuel clause over recovered 26 51 Estimated loss on Kemper IGCC 484 451 Pension and other benefits 96 92 Federal NOL 109 17 Property insurance 27 25 Premium on long-term debt 14 18 AROs 72 71 Property basis difference — 451 Deferred state tax assets 113 152 Deferred federal tax assets 31 31 Federal effect of state deferred taxes 19 8 Other 33 33 Total 1,024 1,400 Total deferred tax liabilities, net 756 762 Accumulated deferred income taxes $ 756 $ 762 The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation. At December 31, 2016 , the tax-related regulatory assets were $362 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, 2016 , the tax-related regulatory liabilities were $7 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 2016, 2015, and 2014. At December 31, 2016 , the Company had state of Mississippi NOL carryforwards totaling approximately $3 billion , resulting in deferred tax assets of approximately $112 million . The NOLs will expire between 2032 and 2037. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate (35.0 )% (35.0 )% (35.0 )% State income tax, net of federal deduction (5.7 ) (6.3 ) (4.0 ) Non-deductible book depreciation 0.7 1.3 0.1 AFUDC-equity (28.5 ) (49.6 ) (7.8 ) Other — (2.9 ) 0.1 Effective income tax rate (benefit rate) (68.5 )% (92.5 )% (46.6 )% The decrease in the Company's 2016 effective tax rate (benefit rate), as compared to 2015, is primarily due to an increase in estimated losses associated with the Kemper IGCC and an increase in non-taxable AFUDC equity. 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, partially offset by a decrease in non-taxable AFUDC equity. On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2016 2015 2014 (in millions) Unrecognized tax benefits at beginning of year $ 421 $ 165 $ 4 Tax positions increase from current periods 26 32 58 Tax positions increase from prior periods 18 224 103 Balance at end of year $ 465 $ 421 $ 165 The tax positions increases from current periods and prior periods for 2016, 2015 and 2014 relate to deductions for R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. The impact on the Company's effective tax rate, if recognized, is as follows: 2016 2015 2014 (in millions) Tax positions impacting the effective tax rate $ 1 $ (2 ) $ 4 Tax positions not impacting the effective tax rate 464 423 161 Balance of unrecognized tax benefits $ 465 $ 421 $ 165 The tax positions not impacting the effective tax rate relate to deductions for R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. Accrued interest for unrecognized tax benefits was as follows: 2016 2015 2014 (in millions) Interest accrued at beginning of year $ 13 $ 3 $ 1 Interest accrued during the year 15 10 2 Balance at end of year $ 28 $ 13 $ 3 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 and U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See "Section 174 Research and Experimental Deduction" herein for additional information. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 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, reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. 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. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, the Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest of $28 million as of December 31, 2016. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.
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, unitary, or consolidated. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal — Current (*) $ 928 $ 12 $ 179 Deferred (*) (1,098 ) 10 (166 ) (170 ) 22 13 State — Current (60 ) (32 ) (14 ) Deferred 35 31 (2 ) (25 ) (1 ) (16 ) Total $ (195 ) $ 21 $ (3 ) (*) ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $1.13 billion for 2016 , $246 million for 2015 , and $305 million for 2014. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits. The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2016 2015 Deferred tax liabilities — Accelerated depreciation and other property basis differences $ 2,440 $ 1,364 Levelized capacity revenues 28 22 Other 27 7 Total deferred income tax liabilities 2,495 1,393 Deferred tax assets — Federal effect of state deferred taxes 53 40 Basis difference on ITCs 292 149 Alternative minimum tax carryforward 15 15 Unrealized tax credits 1,685 551 Federal net operating loss (NOL) 808 9 Deferred state tax assets 60 13 Other partnership basis differences 16 3 Other 8 14 Total deferred income tax assets 2,937 794 Valuation Allowance — (2 ) Net deferred income tax assets 2,937 792 Total deferred income tax asset (liability) $ 442 $ (601 ) Recognized in the consolidated balance sheets: Accumulated deferred income taxes – assets $ 594 $ — Accumulated deferred income taxes – liability $ (152 ) $ (601 ) Deferred tax liabilities are primarily the result of property-related timing differences. The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation. Deferred tax assets consist primarily of timing differences related to the carryforward of unrealized federal ITCs, PTCs, net operating loss, and net basis differences on federal ITCs. Tax Credit Carryforwards At December 31, 2016, the Company had federal ITC and PTC carryforwards, which are expected to result in $1.7 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be fully utilized by 2022. The acquisition of additional renewable projects and carrying back the federal NOL, as well as potential tax reform legislation, could further delay the utilization of existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time. Net Operating Loss Southern Company is expecting a consolidated federal net operating loss of approximately $2.8 billion for income tax purposes for the 2016 tax year. Portions of the NOL are expected to be carried back to prior tax years and forward to future tax years. The ultimate outcome of this matter cannot be determined at this time. The Company had state NOL carryforwards of $1.0 billion and $225 million at December 31, 2016 and December 31, 2015, respectively, which will expire from 2029 to 2035. These carryforwards resulted in deferred tax assets of $40 million as of December 31, 2016 and $8 million as of December 31, 2015. The state NOL carryforwards by jurisdiction were as follows: Jurisdiction NOL Carryforwards Net State Income Tax Benefit Tax Year NOL Expires (in millions) Oklahoma $ 838 $ 32 2035 Florida 185 7 2033 Other states 7 1 2029 through 2035 Balance at year end $ 1,030 $ 40 Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction (9.1 ) (0.3 ) (6.0 ) Amortization of ITC (20.6 ) (5.0 ) (4.3 ) ITC basis difference (89.0 ) (21.5 ) (27.7 ) Production tax credits (23.3 ) (0.6 ) — Noncontrolling interests (6.2 ) (1.7 ) (0.3 ) Other 4.6 2.5 1.4 Effective income tax rate (benefit) (108.6 )% 8.4 % (1.9 )% The Company's effective tax rate decreased in 2016 and increased in 2015 primarily due to changes in federal ITCs. The Company's deferred federal ITCs are amortized to income tax expense over the life of the respective asset. ITCs amortized in this manner amounted to $37 million in 2016, $19 million in 2015, and $11 million in 2014. Also, the Company received cash related to federal ITCs under the renewable energy incentives of $162 million and $74 million for the years ended December 31, 2015 and 2014, respectively. No cash was received related to these incentives in 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $173 million in 2016, $54 million in 2015, and $48 million in 2014. The tax benefit of PTCs reduced income tax expense by $42 million in 2016 and $1 million in 2015. See "Unrecognized Tax Benefits" below for further information. Unrecognized Tax Benefits Changes during the year in unrecognized tax benefits were as follows: 2016 2015 2014 (in millions) Balance at beginning of year $ 8 $ 5 $ 2 Tax positions increase from current periods 17 9 5 Tax positions decrease from prior periods (8 ) (6 ) (2 ) Balance at end of year $ 17 $ 8 $ 5 The increase in unrecognized tax benefits from current periods for 2016, 2015, and 2014, and the decrease from prior periods in 2016 and 2015, primarily relate to federal income tax benefits from deferred ITCs and would all impact the Company's effective tax rate, if recognized. The impact on the effective tax rate is determined based on the amount of ITCs which are uncertain. If these tax positions are not able to be recognized due to a federal audit adjustment in the amount that has been estimated, the amount of tax credit carryforwards discussed above would be reduced by approximately $92 million . 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, 2014, and 2015 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.
Southern Company Gas [Member]
Income Tax Disclosure [Line Items]
INCOME TAXES	INCOME TAXES Subsequent to the Merger, Southern Company will file a consolidated federal income tax return and various combined and separate state income tax returns on behalf of the Company. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Prior to the Merger, the Company filed a U.S. federal consolidated income tax return and various state income tax returns. Current and Deferred Income Taxes Details of income tax provisions for the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 are as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 (in millions) (in millions) Federal — Current $ — $ 67 $ (13 ) $ 111 Deferred 65 8 198 184 65 75 185 295 State — Current (16 ) 12 10 38 Deferred 27 — 18 17 11 12 28 55 Total $ 76 $ 87 $ 213 $ 350 Net cash payments (refunds) for income taxes for the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 were $23 million , $(100) million , $(26) million , and $422 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: Successor Predecessor 2016 2015 (in millions) (in millions) Deferred tax liabilities — Accelerated depreciation $ 1,954 $ 1,820 Property basis differences 311 283 Regulatory assets associated with employee benefit obligations 125 44 Other 164 215 Total 2,554 2,362 Deferred tax assets — Federal net operating loss 59 — Federal effect of state deferred taxes 42 62 Employee benefit obligations 165 164 Other 332 212 Total 598 438 Less valuation allowances (19 ) (19 ) Total, net of valuation allowances 579 419 Accumulated deferred income taxes, net $ 1,975 $ 1,943 In November 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. See Note 1 under "Recently Issued Accounting Standards" for additional information. At December 31, 2016 , the tax-related regulatory liabilities to be credited to customers were $22 million . These liabilities are primarily attributable to unamortized ITCs. Deferred federal and state ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1 million for the successor period of July 1, 2016 through December 31, 2016 and, for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014, were $1 million , $2 million , and $2 million , respectively. At December 31, 2016 , all ITCs available to reduce federal income taxes payable had been utilized. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 Federal statutory rate 35.0% 35.0% 35.0% 35.0% State income tax, net of federal 4.0 3.5 3.4 3.8 Other 1.0 (0.9) (2.0) (1.2) Effective income tax rate 40.0% 37.6% 36.4% 37.6% The Company's effective tax rates for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 were impacted by certain nondeductible Merger-related expenses. The effective tax rate for the successor period of July 1, 2016 through December 31, 2016 was also impacted by certain nondeductible expenses associated with change-in-control compensation charges. On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rates. See Note 1 under "Recently Issued Accounting Standards" for additional information. Unrecognized Tax Benefits The Company has no unrecognized tax benefits for any period presented. The Company classifies interest on tax uncertainties as interest expense; however, the Company had no accrued interest or penalties for unrecognized tax benefits for any period presented. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. On July 1, 2016, the Company became a wholly-owned subsidiary of Southern Company, which is a participant in the Compliance Assurance Process of the IRS. The audits for the Company by the IRS or any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for years prior to 2012.

Financing

Financing	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 , 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, 2016 and 2015 , 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: 2016 2015 (in millions) Senior notes $ 1,995 $ 1,810 Other long-term debt 485 829 Pollution control revenue bonds (*) 76 4 Capitalized leases 32 32 Unamortized debt issuance expense (1 ) (1 ) Total $ 2,587 $ 2,674 (*) Includes $40 million of pollution control revenue bonds classified as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. Maturities through 2021 applicable to total long-term debt are as follows: $2.6 billion in 2017 ; $3.9 billion in 2018 ; $3.2 billion in 2019 ; $1.4 billion in 2020 ; and $3.1 billion in 2021 . Bank Term Loans Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. At December 31, 2016 , Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million , $45 million , $100 million , $1.2 billion , and $380 million , respectively, of which $2.0 billion are reflected in the statements of capitalization as long-term debt and $100 million are reflected in the balance sheet as notes payable. At December 31, 2015 , Southern Company, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million , $900 million , and $400 million , respectively . In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million , one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR. In March 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion . Mississippi Power borrowed $900 million in March 2016 under the term loan agreement and the remaining $300 million in October 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans in March 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. This loan matures on April 1, 2018 and bears interest based on one-month LIBOR. In May 2016, Gulf Power entered into an 11 -month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes. In September 2016, Southern Power Company repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power Company entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes. The outstanding bank loans as of December 31, 2016 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, 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, 2016 , each of Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits. DOE Loan Guarantee Borrowings Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into 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 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 June and December 2016, Georgia Power made borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million and $125 million , respectively. The interest rate applicable to the $300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142% , both for an interest period that extends to the final maturity date of February 20, 2044. At December 31, 2016 and 2015 , Georgia Power had $2.6 billion and $2.2 billion of borrowings outstanding under the FFB Credit Facility, respectively. 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). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle 3 and 4 Agreement; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. 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 $13.3 billion of senior notes in 2016 . Southern Company issued $8.5 billion and its subsidiaries issued a total of $4.8 billion . These amounts include senior notes issued by Southern Company Gas subsequent to the Merger. The proceeds of Southern Company's issuances were used to fund a portion of the consideration for the Merger and related transaction costs and for general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs, and, for Southern Power, its growth strategy. Certain of Georgia Power's and Southern Power's issuances were allocated to eligible renewable energy expenditures. The proceeds of Southern Company Gas' issuances were primarily used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), to fund the purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar Energy Services, LLC (SouthStar), and to make a voluntary contribution to Southern Company Gas' pension plan. See Note 12 under " Southern Company – Investment in Southern Natural Gas " and " – Acquisition of Remaining Interest in SouthStar " for additional information. At December 31, 2016 and 2015 , Southern Company and its subsidiaries had a total of $33.0 billion and $19.1 billion , respectively, of senior notes outstanding. At December 31, 2016 and 2015 , Southern Company had a total of $10.3 billion and $2.4 billion , respectively, of senior notes outstanding. These amounts include senior notes due within one year. Subsequent to December 31, 2016, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2007A 5.55% Senior Notes due February 1, 2017. 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 At December 31, 2016 and 2015 , Southern Company had a total of $2.4 billion and $1.0 billion , respectively, of junior subordinated notes outstanding. In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes. In December 2016, Southern Company issued $550 million aggregate principal amount of Series 2016B Junior Subordinated Notes due March 15, 2057, which bear interest at a fixed rate of 5.50% per year up to, but not including, March 15, 2022. From, and including, March 15, 2022, the Series 2016B Junior Subordinated Notes will bear interest at a floating rate based on three-month LIBOR. The proceeds were used for general corporate purposes. Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2016 and 2015 , which includes pollution control revenue bonds due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. Plant Daniel Revenue Bonds In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See " Assets Subject to Lien " herein for additional information. Gas Facility Revenue Bonds Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas, is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2016 was $200 million . 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, 2016 and 2015 . Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. First Mortgage Bonds Nicor Gas, a subsidiary of Southern Company Gas, had $625 million of first mortgage bonds outstanding at December 31, 2016 . These bonds have been issued with maturities ranging from 2019 to 2038. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See " Assets Subject to Lien " herein for additional information. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt. In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2016 and 2015 of approximately $74 million and $77 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. See Note 3 under " Integrated Coal Gasification Combined Cycle " for additional information regarding the Kemper IGCC. At December 31, 2016 and 2015 , the capitalized lease obligations for Georgia Power's corporate headquarters building were $28 million and $35 million , respectively, with an annual interest rate of 7.9% for both years. At December 31, 2016 and 2015 , Alabama Power had capitalized lease obligations of $4 million and $5 million , respectively, for a natural gas pipeline with an annual interest rate of 6.9% . At December 31, 2016 and 2015 , a subsidiary of Southern Company had capital lease obligations of approximately $29 million and $30 million , respectively, for certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.4% to 3.4% . 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, 2016 . 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. The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See " First Mortgage Bonds " herein for additional information. During 2016, in accordance with its overall growth strategy, Southern Power acquired the Mankato project. Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. See Note 12 under "Southern Power" for additional information. Bank Credit Arrangements At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year Company 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 35 500 800 1,335 1,335 — — — 35 Georgia Power — — 1,750 1,750 1,732 — — — — Gulf Power 85 195 — 280 280 45 — 25 60 Mississippi Power 173 — — 173 150 — 13 13 160 Southern Power Company (b) — — 600 600 522 — — — — Southern Company Gas (c) 75 1,925 — 2,000 1,949 — — — 75 Other 55 — — 55 55 20 — 20 35 Southern Company Consolidated $ 423 $ 3,620 $ 4,400 $ 8,443 $ 8,273 $ 65 $ 13 $ 58 $ 365 (a) Represents the Southern Company parent entity. (b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 under " Southern Power " for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million . (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1 / 4 of 1% for Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder. Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of 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, 2016 , Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants. A portion of the $8.3 billion unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2016 was approximately $1.9 billion . In addition, at December 31, 2016 , the traditional electric operating companies had approximately $0.4 billion of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2016: Commercial paper $ 1,909 1.1 % Short-term bank debt 123 1.7 % Total $ 2,032 1.1 % December 31, 2015: Commercial paper $ 740 0.7 % Short-term bank debt 500 1.4 % Total $ 1,240 0.9 % In addition to the short-term borrowings in the table above, Southern Power's subsidiary Project Credit Facilities had total amounts outstanding of $209 million and $137 million at a weighted average interest rate of 2.1% and 2.0% as of December 31, 2016 and 2015 , respectively. The amounts outstanding as of December 31, 2016 under the Project Credit Facilities were fully repaid subsequent to December 31, 2016 . Redeemable Preferred Stock of Subsidiaries Each of the traditional electric 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 "Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity. The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) Balance at December 31, 2013 $ 375 Issued — Redeemed — Balance at December 31, 2014 375 Issued — Redeemed (262 ) Other 5 Balance at December 31, 2015 118 Issued — Redeemed — Balance at December 31, 2016 $ 118
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, 2016 and 2015 , 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, 2016 and 2015 , 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, 2016 and 2015 , the Company had $561 million and $200 million , respectively, of senior notes and pollution control revenue bonds due within one year. Maturities through 2021 applicable to total long-term debt are as follows: $561 million in 2017 ; $200 million in 2019 ; $250 million in 2020 ; and $310 million in 2021 . There are no material scheduled maturities in 2018. Bank Term Loans In March 2016, the Company entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million , one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR. These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. At December 31, 2016 , the Company was in compliance with its debt limits. Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control and solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2016. The Company had $1.1 billion of tax-exempt pollution control revenue bond obligations outstanding at each of December 31, 2016 and 2015 , including pollution control revenue bonds due within one year. Senior Notes In January 2016, 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 the Company's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including the Company's continuous construction program. At December 31, 2016 and 2015 , the Company had $5.8 billion and $5.6 billion of senior notes outstanding, respectively, including senior notes due within one year. As of December 31, 2016, the Company did not have any outstanding secured debt. Subsequent to December 31, 2016, the Company repaid at maturity $200 million aggregate principal amount of its Series 2007A 5.55% Senior Notes due February 1, 2017. 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. The Company's outstanding preference stock is 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. 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 6.45% Preference Stock $25 6,000,000 Stated Capital (*) 6.50% Preference Stock $25 2,000,000 Stated Capital (*) (*) Also includes a make-whole premium prior to October 1, 2017 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, 2016 and 2014 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, 2016 , committed credit arrangements with banks were as follows: Expires Expires Within One Year 2017 2018 2020 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) $ 35 $ 500 $ 800 $ 1,335 $ 1,335 $ — $ 35 Most of the bank credit arrangements require payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1 / 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 level to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. At December 31, 2016 , the Company was in compliance with the debt limit covenants. A portion of the unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $890 million as of December 31, 2016 . In addition, at December 31, 2016, the Company had $87 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, 2016 and 2015 , there was no short-term debt outstanding. At December 31, 2016 , the Company had regulatory approval to have outstanding up to $2.1 billion of short-term borrowings.
Southern Company Gas [Member]
Debt Disclosure [Line Items]
FINANCING	FINANCING Southern Company Gas' 100% -owned subsidiary, Southern Company Gas Capital, was established to provide for certain of Southern Company Gas' ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital and the gas facility revenue bonds issued by Pivotal Utility Holdings. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs. Securities Due Within One Year The current portion of long-term debt at December 31, 2016 is composed of the portion of its long-term debt due within the next 12 months. At December 31, 2016 , the Company had $22 million of medium-term notes due within one year, consisting of medium-term notes of Atlanta Gas Light. At December 31, 2015 , the Company had $545 million of first mortgage bonds and senior notes due within one year. Certain of the Company's senior notes with a principal amount of $275 million were subject to change-in-control provisions that were triggered by the Merger. Under the applicable note purchase agreement, Southern Company Gas Capital was required to provide notice to the holders of these notes of the change in control and offer to prepay these notes in August 2016. None of the holders of these notes accepted the offer for prepayment. These senior notes remained on their original payment schedules and included $120 million aggregate principal amount of Series A Floating Rate notes that were repaid at maturity on October 27, 2016 and $155 million aggregate principal amount of 3.50% Senior Notes due October 27, 2018. Long-Term Debt Long-term debt of the Company at December 31, 2016 and 2015 consisted of Series A, Series B, and Series C medium-term notes of Atlanta Gas Light; senior notes of Southern Company Gas Capital; first mortgage bonds of Nicor Gas; and gas facility revenue bonds of Pivotal Utility Holdings. Southern Company Gas fully and unconditionally guarantees all of Southern Company Gas Capital's senior notes and Pivotal Utility Holdings' gas facility revenue bonds. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. The majority of the long-term debt matures after fiscal year 2021. The amount of medium-term notes outstanding at December 31, 2016 and December 31, 2015 was $159 million and $181 million , respectively. Maturities through 2021 applicable to total long-term debt are as follows: $22 million in 2017; $155 million in 2018; $350 million in 2019; $330 million in 2021; and thereafter $3.9 billion . There are no material scheduled maturities in 2020. First Mortgage Bonds The first mortgage bonds of Nicor Gas have been issued with maturities ranging from 2019 to 2038. In February and May 2016, $75 million and $50 million , respectively, of Nicor Gas' first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings. In June 2016, Nicor Gas issued $250 million aggregate principal amount of first mortgage bonds with the following terms: $100 million at 2.66% due June 20, 2026, $100 million at 2.91% due June 20, 2031, and $50 million at 3.27% due June 20, 2036. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The amount of first mortgage bonds outstanding at December 31, 2016 and December 31, 2015 was $625 million and $375 million , respectively. Gas Facility Revenue Bonds Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from each issuance then are loaned to Pivotal Utility Holdings. The amount of gas facility revenue bonds outstanding at December 31, 2016 and December 31, 2015 was $200 million . Senior Notes In May 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 3.25% Senior Notes due June 15, 2026, which are guaranteed by Southern Company Gas. The proceeds were used to repay at maturity $300 million aggregate principal amount of 6.375% Senior Notes due July 15, 2016 and for general corporate purposes. In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for a 50% equity interest in SNG, to fund the purchase of Piedmont's interest in SouthStar, to make a voluntary contribution to the pension plan, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. The amount of senior notes outstanding at December 31, 2016 and December 31, 2015 was $3.7 billion and $2.5 billion , respectively. Dividend Restrictions By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of December 31, 2016, the amount of subsidiary retained earnings restricted for dividend payment totaled $688 million . Bank Credit Arrangements Credit Facilities Bank credit arrangements under the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility provide liquidity support to Southern Company Gas Capital's and Nicor Gas' commercial paper borrowings. The Nicor Gas Credit Facility is restricted for working capital needs of Nicor Gas. In October 2015, the Company entered into agreements to amend and extend the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility. Under the terms of these agreements, the Company extended the maturity dates of the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility to November 9, 2018 and December 14, 2018, respectively. One of the banks elected not to participate in this extension and its total commitment of $75 million will continue through the fourth quarter 2017. The Company also modified the credit facilities to provide for the limited consent by the lenders to the Merger with Southern Company. Additionally, the Company made similar changes to its Bank Rate Mode Covenants Agreement relating to the Pivotal Utility Holdings gas facility revenue bonds. At December 31, 2016 , committed credit arrangements with banks were as follows: Successor Expires Expires Within One Year Company 2017 2018 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) Southern Company Gas Capital $ 49 $ 1,251 $ 1,300 $ 1,249 $ — $ 49 Nicor Gas 26 674 700 700 — 26 Total $ 75 $ 1,925 $ 2,000 $ 1,949 $ — $ 75 The Southern Company Gas Credit Facility and the Nicor Gas Credit Facility included in the table above each contain a covenant that limits the ratio of debt to capitalization (as defined in each Facility) to a maximum of 70% and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of the applicable company. At December 31, 2016 , the Company and Nicor Gas were in compliance with their respective debt limit covenants. Commercial Paper Programs The Company maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas that consist of short-term, unsecured promissory notes. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of the Company's other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. Commercial paper is included in notes payable in the consolidated balance sheets. Details of commercial paper borrowings outstanding were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) Successor – December 31, 2016: Southern Company Gas Capital $ 733 1.09 % Nicor Gas 524 0.95 % Total $ 1,257 1.03 % Predecessor – December 31, 2015: Southern Company Gas Capital $ 471 0.71 % Nicor Gas 539 0.52 % Total $ 1,010 0.60 % CAPITALIZATION The capitalization for the years ended December 31, 2016 and 2015 are as follows: Successor Predecessor Successor Predecessor 2016 2015 2016 2015 (in millions) (in millions) (percent of total) (percent of total) Long-Term Debt: Long-term notes payable — 1.47% to 9.10% due 2016-2046 (a) $ 3,887 $ 3,181 Other long-term debt — First mortgage bonds — 2.66% to 6.58% due 2016-2038 (b) 625 375 Gas facility revenue bonds — Variable rate (1.28% at 1/1/17) due 2022-2033 200 200 Total other long-term debt 825 575 Unamortized fair value adjustment of long-term debt 578 68 Unamortized debt discount (9 ) (4 ) Total long-term debt (annual interest requirement — $207 million) 5,281 3,820 Less amount due within one year 22 545 Long-term debt excluding amount due within one year 5,259 3,275 36.6 % 45.2 % Common Stockholder's Equity: Common stock — 2016: par value $0.01 per share — 2015 par value $5 per share Authorized — 2016: 100 million shares — 2015: 750 million shares Outstanding — 2016: 100 shares — 2015: 120.4 million shares Treasury — 2016: no shares — 2015: 0.2 million shares Paid-in capital 9,095 2,702 Treasury, at cost — (8 ) Retained earnings (accumulated deficit) (12 ) 1,421 Accumulated other comprehensive income (loss) 26 (186 ) Total common stockholder's equity 9,109 3,929 63.4 54.2 Noncontrolling interest — 46 — 0.6 Total stockholders' equity 9,109 3,975 Total Capitalization $ 14,368 $ 7,250 100.0 % 100.0 % (a) Long-term notes payable maturities are as follows: $22 million in 2017 ( 7.20% ); $155 million in 2018 ( 3.50% ); $300 million in 2019 ( 5.25% ); $330 million in 2021 ( 3.50% to 9.10% ); and $3.1 billion in 2022 - 2046 ( 2.45% to 8.70% ). (b) First mortgage bonds maturities are as follows: $50 million in 2019 ( 4.70% ) and $575 million in 2023 - 2038 ( 2.66% t
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: 2016 2015 (in millions) Senior notes $ 450 $ 700 Pollution control revenue bonds — 4 Capital leases 10 8 Total $ 460 $ 712 Maturities through 2021 applicable to total long-term debt are as follows: $460 million in 2017 ; $762 million in 2018 ; $513 million in 2019 ; $57 million in 2020 ; and $376 million in 2021 . Senior Notes In March 2016, the Company issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 is being allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of the Company's Series 2013B Floating Rate Senior Notes due March 15, 2016, 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, 2016 and 2015 , the Company had $6.2 billion and $6.3 billion of senior notes outstanding, respectively, which included senior notes due within one year. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $2.8 billion and $2.4 billion at December 31, 2016 and 2015 , respectively. As of December 31, 2016 , the Company's secured debt included borrowings of $2.6 billion guaranteed by the DOE and capital lease obligations of $169 million . As of December 31, 2015 , the Company's secured debt included borrowings of $2.2 billion guaranteed by the DOE and capital lease obligations of $183 million . See Note 7 and "DOE Loan Guarantee Borrowings" herein for additional information. Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bond obligations outstanding at both December 31, 2016 and 2015 was $1.8 billion . 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 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 June and December 2016, the Company made borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million and $125 million , respectively. The interest rate applicable to the $300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142% , both for an interest period that extends to the final maturity date of February 20, 2044. At December 31, 2016 and 2015 , the Company had $2.6 billion and $2.2 billion of borrowings outstanding under the FFB Credit Facility, respectively. 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). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle 3 and 4 Agreement; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by the Company if authorized by the Georgia PSC; and (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or the Company's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. 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, 2016 and 2015 , the Company had a capital lease asset for its corporate headquarters building of $61 million , with accumulated depreciation at December 31, 2016 and 2015 of $33 million and $26 million , respectively. At December 31, 2016 and 2015 , the capitalized lease obligation was $28 million and $35 million , respectively, with an annual interest rate of 7.9% for both years. For ratemaking purposes, the Georgia PSC has allowed the lease payments in cost of service with no return on the capital lease asset. The difference between the depreciation and the lease payments allowed for ratemaking purposes is recovered as operating expenses as ordered by the Georgia PSC. The annual operating expense incurred for this capital lease was not material for any year presented. At December 31, 2016 and 2015 , the Company had capital lease assets related to two PPAs with Southern Power of $149 million , with accumulated amortization at December 31, 2016 and 2015 of $19 million and $10 million , respectively. At December 31, 2016 and 2015 , the related capitalized lease obligations were $141 million and $148 million , respectively. The annual interest rates range from 10% to 11% for these two capital lease PPAs. For ratemaking purposes, the Georgia PSC has included the capital lease asset amortization in cost of service and the interest in the Company's cost of debt. See Note 1 under "Affiliate Transactions" and Note 7 under "Fuel and Purchased Power Agreements" for additional information. Assets Subject to Lien See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of the Company that are secured by a first priority lien on (i) the Company's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. See "Capital Leases" above for information regarding certain assets held under capital leases. Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its 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, 2016 , the Company had a $1.75 billion committed credit arrangement with banks, of which $1.73 billion was unused. This credit arrangement expires in 2020. This bank credit arrangement requires payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1 / 4 of 1% for the Company. This bank credit arrangement contains a covenant that limits the Company's debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes certain hybrid securities. At December 31, 2016 , the Company was in compliance with the debt limit covenant. Subject to applicable market conditions, the Company expects to renew this bank credit arrangement, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder. A portion of the $1.73 billion unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was $868 million . In addition, at December 31, 2016, the Company had $250 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 arrangement described above. Commercial paper is included in notes payable in the balance sheets. Details of commercial paper borrowings outstanding were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2016 $ 392 1.1 % December 31, 2015 $ 158 0.6 %
Gulf Power [Member]
Debt Disclosure [Line Items]
FINANCING	FINANCING Securities Due Within One Year At December 31, 2016 and 2015, the Company had $87 million and $110 million of long-term debt due within one year , respectively. Maturities through 2021 applicable to total long-term debt include $87 million in 2017 and $175 million in 2020. There are no scheduled maturities in 2018, 2019, or 2021. Bank Term Loans In May 2016, the Company entered into an 11 -month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes. 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 certain hybrid securities. At December 31, 2016 , the Company was in compliance with its debt limit. Senior Notes At December 31, 2016 and 2015 , the Company had a total of $777 million and $1.01 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, 2016 and 2015 . In May 2016, the Company redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051. Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bond obligations outstanding at December 31, 2016 and 2015 was $309 million . Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company's preferred stock and Class A preferred stock, without preference between classes, 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, 2016 . 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. Subsequent to December 31, 2016, the Company issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million . The proceeds were used for general corporate purposes, including the Company's continuous construction program. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Assets Subject to Lien The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2016 . 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, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2017 2018 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $ 85 $ 195 $ 280 $ 280 $ 45 $ — $ 25 $ 60 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, 2016 , the Company was in compliance with these covenants. Most of the $280 million of unused credit arrangements with banks provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was approximately $82 million . In addition, at December 31, 2016 , the Company had $86 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: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2016: Commercial paper $ 168 1.1% Short-term bank debt 100 1.5% Total $ 268 1.2% December 31, 2015: Commercial paper $ 142 0.7%
Mississippi Power [Member]
Debt Disclosure [Line Items]
FINANCING	FINANCING Going Concern As of December 31, 2016, the Company's current liabilities exceeded current assets by approximately $371 million primarily due to $551 million in promissory notes to Southern Company which mature in December 2017, $35 million in senior notes which mature in November 2017, and $63 million in short-term debt. The Company expects the funds needed to satisfy the promissory notes to Southern Company will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, the Company intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, the Company has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to (i) extend the maturity of the $551 million in promissory notes and (ii) provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, the Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company, consistent with the requirements of ASU 2014-15. See Note 1 under "Recently Issued Accounting Standards" for additional information regarding ASU 2014-15. Parent Company Loans and Equity Contributions On January 28, 2016, the Company issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During 2016, the Company borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On June 27, 2016, the Company received a capital contribution from Southern Company of $225 million , the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. Also, on December 14, 2016, the Company received a capital contribution from Southern Company of $400 million , the proceeds of which were used for general corporate purposes. As of December 31, 2016 and 2015, the amount of outstanding promissory notes to Southern Company totaled $551 million and $576 million , respectively. Bank Term Loans In March 2016, the Company entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion . The Company borrowed $900 million in March 2016 under the term loan agreement and the remaining $300 million in October 2016. The Company used the initial proceeds to repay $900 million in maturing bank loans in March 2016 and the remaining $300 million to repay at maturity the Company's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. 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 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, 2016 , the Company was in compliance with its debt limit. At December 31, 2016 , the Company had a total of $1.2 billion in bank loans outstanding. 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. Senior Notes At December 31, 2016 and 2015 , the Company had $790 million and $1.1 billion of senior notes outstanding, respectively, which included senior notes due within one year. These senior notes are effectively subordinated to the secured debt of the Company. See "Plant Daniel Revenue Bonds" below for additional information regarding the Company's secured indebtedness. Plant Daniel Revenue Bonds In 2011, in connection with the Company's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, the Company assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. These bonds are secured by Plant Daniel Units 3 and 4 and certain related personal property. The bonds were recorded at fair value as of the date of assumption, or $346 million , reflecting a premium of $76 million . See "Assets Subject to Lien" herein for additional information. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2016 and 2015 was as follows: 2016 2015 (in millions) Parent company loans $ 551 $ — Senior notes 35 300 Bank term loans — 425 Pollution control revenue bonds (*) 40 — Capitalized leases 3 3 Outstanding at December 31 $ 629 $ 728 (*) Pollution control revenue bonds are classified as short term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. Maturities through 2021 applicable to total long-term debt are as follows: $629 million in 2017, $1.2 billion in 2018, $128 million in 2019, $10 million in 2020, and $274 million in 2021. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of pollution control revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2016 and 2015 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, 2016 and 2015 . 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, 2016 and 2015 of $74 million and $77 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 2016 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. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC. 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 (*) $ 100 300,000 $ 100.00 (*) There are 1,200,000 outstanding depositary shares, each representing one-fourth of a share of the 5.25% preferred stock. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Bank Credit Arrangements At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2017 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $173 $173 $150 $— $13 $13 $160 Subject to applicable market conditions, the Company expects to renew its bank credit arrangements, as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. Most of these bank credit arrangements require payment of commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. Most of these bank credit arrangements contain covenants that limit the Company's debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. A portion of the $150 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, 2016 was $40 million . At December 31, 2016 and 2015 , there was no commercial paper debt outstanding. At December 31, 2016 and 2015 , there was $23 million and $500 million , respectively, of short-term debt outstanding.
Southern Power [Member]
Debt Disclosure [Line Items]
FINANCING	FINANCING Southern Power Company's senior notes, bank term loans, commercial paper, and credit facility are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Compan y. The Company's subsidiaries are not issuers, borrowers, or obligors, as applicable, under the senior notes, bank term loans, commercial paper, or the Facility (as defined herein). The se nior notes, bank term loans, commercial paper, and the Facility are effectively subordinated to any future secured debt and any potential claims of creditors of the Company's subsidiaries. As of December 31, 2016 , the Company had no secured debt other than indebtedness outstanding under the subsidiary project credit facilities discussed below. Securities Due Within One Year At December 31, 2016 , the Company had a $60 million bank loan and $500 million of senior notes due within one year. At December 31, 2015 , the Company had a $400 million bank loan due within one year. In addition, the Company classified as due within one year approximately $1 million and $3 million of long-term notes payable to TRE at December 31, 2016 and 2015, respectively. Maturities of long-term debt are as follows: December 31, 2016 (in millions) 2017 $ 561 2018 670 2019 600 2020 300 2021 300 Senior Notes In June 2016, the Company issued € 600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and € 500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The net proceeds are being allocated to renewable energy generation projects. The Company's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through foreign currency swaps, mitigating foreign currency exchange rate risk associated with the interest and principal payments. See Note 9 under "Foreign Currency Derivatives" for additional information. In September 2016, the Company issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including the Company's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the subsidiary project credit facilities, discussed below. In November 2016, the Company issued $600 million aggregate principal amount of Series 2016D 1.95% Senior Notes due December 15, 2019, $300 million aggregate principal amount of Series 2016E 2.50% Senior Notes due December 15, 2021, and $400 million aggregate principal amount of Series 2016F 4.95% Senior Notes due December 15, 2046. The net proceeds of the Series 2016D and the Series 2016E Senior Notes are being allocated to renewable energy generation projects. The proceeds of the Series 2016F Senior Notes were used to redeem, in December 2016, all of the $200 million aggregate principal amount of the Company's Series E 6.375% Senior Notes due November 15, 2036 and to repay outstanding short-term indebtedness. At December 31, 2016 and 2015 , the Company had $5.3 billion and $2.7 billion of senior notes outstanding, respectively, which included senior notes due within one year. Other Long-Term Notes During 2016 , the Company repaid $6 million and issued $5 million of long-term notes payable to TRE due 2035 through 2036 related to the financing of Calipatria, Morelos, and Rutherford. At December 31, 2016 and 2015 , the Company had $15 million and $13 million , respectively, of long-term notes payable to TRE. In September 2016, the Company repaid $80 million of an outstanding $400 million floating rate bank term loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, the Company entered into a $60 million aggregate principal amount floating rate bank term loan bearing interest based on one-month LIBOR due September 2017, which is included in securities due within one year on the consolidated balance sheets. The proceeds were used to repay existing indebtedness and for other general corporate purposes. Each of these bank term loan agreements has a covenant that limits debt levels to 65% of total capitalization, as defined by the agreements. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2016 , the Company was in compliance with its debt limits. Asset Subject to Lien During 2016, in accordance with its overall growth strategy, the Company acquired the Mankato project. Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. See Note 2 for additional information. Bank Credit Arrangements Company Credit Facilities At December 31, 2016 , the Company had a committed credit facility (Facility) of $600 million expiring in 2020. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. As of December 31, 2016 , the total amount available under the Facility was $522 million . As of December 31, 2015 , the total amount available under the Facility was $566 million . The amounts outstanding as of December 31, 2016 and 2015 reflect $78 million and $34 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 expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. The Company 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, 2016 , the Company was in compliance with its debt limits. In December 2016, the Company entered into an agreement for a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the facility was $82 million . The Company's subsidiaries are not parties to the facility. 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. There was no commercial paper outstanding as of December 31, 2016 and 2015 . 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 were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity and Garland Project Credit Facilities were fully repaid on October 14, 2016 and December 29, 2016, respectively. The table below summarizes the Roserock Project Credit Facility as of December 31, 2016, which was extended to and fully repaid on January 31, 2017. Project Construction Loan Facility Bridge Loan Facility Total Loan Facility Loan Facility Undrawn Letter of Credit Facility Letter of Credit Facility Undrawn (in millions) Roserock $ 63 $ 180 $ 243 $ 34 $ 23 $ 16 The Project Credit Facilities had total amounts outstanding of $209 million and $137 million , at a weighted average interest rate of 2.1% and 2.0% , as of December 31, 2016 and 2015, respectively. 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, 2016
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 2016 , 2015 , and 2014 , the traditional electric operating companies and Southern Power incurred fuel expense of $4.4 billion , $4.8 billion , and $6.0 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 $232 million , $227 million , and $198 million for 2016 , 2015 , and 2014 , respectively. Estimated total obligations under these commitments at December 31, 2016 were as follows: Operating Leases (*) Other (in millions) 2017 $ 242 $ 8 2018 246 7 2019 249 6 2020 246 5 2021 249 5 2022 and thereafter 1,041 43 Total $ 2,273 $ 74 (*) A total of $197 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action. Pipeline Charges, Storage Capacity, and Gas Supply Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 33 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2016 and valued at $106 million . Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2016 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2017 $ 822 2018 602 2019 447 2020 394 2021 352 2022 and thereafter 2,591 Total $ 5,208 Operating Leases The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $169 million , $130 million , and $118 million for 2016 , 2015 , and 2014 , 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, 2016 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2017 $ 31 $ 121 $ 152 2018 19 115 134 2019 10 103 113 2020 10 90 100 2021 8 82 90 2022 and thereafter 11 1,184 1,195 Total $ 89 $ 1,695 $ 1,784 For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $44 million . At the termination of the leases, the lessee may renew the lease, exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. Guarantees In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years . The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018 . In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million . As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees.
Alabama Power [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 2016, 2015, and 2014, the Company incurred fuel expense of $1.3 billion , $1.3 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 $42 million , $38 million , and $37 million for 2016, 2015, and 2014, respectively. Total estimated minimum long-term obligations at December 31, 2016 were as follows: Operating Lease PPAs (in millions) 2017 $ 40 2018 41 2019 43 2020 44 2021 46 2022 47 Total commitments $ 261 SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases The Company has entered into rental agreements for coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense under these agreements was $18 million in 2016 , $19 million in 2015 , and $18 million in 2014 . Of these amounts, $14 million , $13 million , and $14 million for 2016, 2015, and 2014, respectively, relate to the railcar leases and was recovered through the Company's Rate ECR. As of December 31, 2016, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Vehicles & Other Total (in millions) 2017 $ 10 $ 4 $ 14 2018 7 3 10 2019 7 3 10 2020 6 2 8 2021 6 2 8 2022 and thereafter 9 1 10 Total $ 45 $ 15 $ 60 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 $12 million in 2023. There are no obligations under these leases through 2021. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations. Guarantees The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in 2013, which mature in December 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4 for additional information.
Georgia Power [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 2016, 2015, and 2014, the Company incurred fuel expense of $1.8 billion , $2.0 billion , and $2.5 billion , respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. 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 $11 million , $10 million , and $19 million in 2016, 2015, and 2014, 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 $217 million , $203 million , and $167 million for 2016, 2015, and 2014, respectively. Estimated total long-term obligations at December 31, 2016 were as follows: Affiliate Capital Leases Affiliate Operating Leases Non-Affiliate Operating Leases (c) Vogtle Units 1 and 2 Capacity Payments Total (in millions) 2017 $ 22 $ 72 $ 123 $ 8 $ 225 2018 22 63 126 7 218 2019 23 64 127 6 220 2020 23 65 123 5 216 2021 24 66 124 5 219 2022 and thereafter 204 479 882 43 1,608 Total $ 318 $ 809 $ 1,505 $ 74 $ 2,706 Less: amounts representing executory costs (a) 48 Net minimum lease payments 270 Less: amounts representing interest (b) 128 Present value of net minimum lease payments $ 142 (a) Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) a re estimated and included in total minimum lease payments. (b) Calculated using an adjusted incremental borrowing rate to reduce the present value of the net minimum lease payments to fair value. (c) A total of $197 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further 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 electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases In addition to the PPA operating leases discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $28 million for 2016 , $29 million for 2015 , and $28 million for 2014 . The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments. As of December 31, 2016, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Other Total (in millions) 2017 $ 12 $ 7 $ 19 2018 6 7 13 2019 3 6 9 2020 3 6 9 2021 2 6 8 2022 and thereafter 2 13 15 Total $ 28 $ 45 $ 73 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 2013, which mature in December 2018. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. See Note 4 for additional information. In addition, in 2013, the Company entered into an agreement that requires the Company to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years . The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018 . In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million . As discussed earlier in this Note under "Operating Leases," the Company has entered into certain residual value guarantees related to railcar leases.
Gulf Power [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 2016 , 2015 , and 2014 , the Company incurred fuel expense of $432 million , $445 million , and $605 million , respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. In addition, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission, some of which are accounted for as operating leases. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity and transmission-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Capacity expense under a PPA accounted for as an operating lease was $75 million for both 2016 and 2015 and $50 million for 2014 . Estimated total minimum long-term commitments at December 31, 2016 were as follows: Operating Lease PPA (in millions) 2017 $ 79 2018 79 2019 79 2020 79 2021 79 2022 and thereafter 112 Total $ 507 SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases In addition to the operating lease PPA discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $9 million , $14 million , and $15 million for 2016 , 2015 , and 2014 , respectively. Estimated total minimum lease payments under these operating leases at December 31, 2016 were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2017 $ 7 $ 1 $ 8 2018 5 1 6 2019 — 1 1 2020 — — — 2021 — — — 2022 and thereafter — 1 1 Total $ 12 $ 4 $ 16 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 50% share of the lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, was $2 million in both 2016 and 2015 and $3 million in 2014 . The Company's total annual railcar lease payments for 2017 are $2 million and are immaterial for 2018 through 2020. In addition to railcar leases, the Company has operating lease agreements for barges and towboats for the transport of coal to Plant Crist. 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 $5 million in 2016 and $10 million in both 2015 and 2014. The Company's annual barge and towboat payments for 2017 and 2018 are expected to be 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 2016 , 2015 , and 2014 , the Company incurred fuel expense of $343 million , $443 million , and $574 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, 2016 of $41 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 electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $3 million , $5 million , and $10 million for 2016 , 2015 , and 2014 , 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 50% share of the lease costs, charged to fuel stock and recovered through the fuel cost recovery clause, was $2 million in 2016 , $2 million in 2015 , and $3 million in 2014 . The Company's annual railcar lease payments for 2017 will be approximately $1 million . Lease obligations for the period 2018 and thereafter are immaterial. In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plant Daniel. The Company's 50% share of the leases for fuel handling was charged to fuel handling expense annually from 2014 through 2016 ; 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.
Southern Power [Member]
Commitments [Line Items]
COMMITMENTS	COMMITMENTS Fuel Agreements SCS, as agent for the Company and the traditional electric operating companies, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities which are not recognized on the Company's consolidated balance sheets. In 2016 , 2015 , and 2014 , the Company incurred fuel expense of $456 million , $441 million , and $596 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 electric operating companies. Under these agreements, each of the traditional electric operating companies and the Company may be jointly and severally liable. Southern Company has entered into keep-well agreements with each of the traditional electric operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements. Operating Leases The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $22 million , $7 million , and $4 million for 2016 , 2015 , and 2014 , respectively. These amounts include contingent rent expense related to land leases 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, 2016 , estimated minimum lease payments under operating leases were $18 million in 2017 , $19 million in 2018 , $20 million in each of 2019 , 2020 , and 2021 , and $762 million in 2022 and thereafter. The majority of the committed future expenditures are related to land leases for solar and wind facilities. Redeemable Noncontrolling Interests See Note 10.
Southern Company Gas [Member]
Commitments [Line Items]
COMMITMENTS	COMMITMENTS Pipeline Charges, Storage Capacity, and Gas Supply Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to Marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas' and SouthStar's gas commodity purchase commitments of 33 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2016 and valued at $106 million . The Company provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2016 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2017 $ 822 2018 602 2019 447 2020 394 2021 352 2022 and thereafter 2,591 Total $ 5,208 Operating Leases The Company has operating lease agreements with various terms and expiration dates primarily for real estate. Total rent expense was $8 million , $6 million , $12 million , and $13 million for the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014, respectively. The Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease terms. As of December 31, 2016 , the Company's estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments (in millions) 2017 $ 18 2018 17 2019 16 2020 15 2021 15 2022 and thereafter 38 Total $ 119 Financial Guarantees AGL Equipment Leasing Inc. (AEL), a wholly-owned subsidiary of the Company, holds the Company's interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation was not impacted by the 2014 sale of Tropical Shipping and continues for the life of the Triton partnerships. Any payment is effectively limited to the net assets of AEL, which was less than $1 million at December 31, 2016 . The Company believes the likelihood of any such payment by AEL is remote and, as such, no liability has been recorded for this obligation at December 31, 2016 . Indemnities In certain instances, the Company has undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which it may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup. See Note 3 under "Environmental Matters" for additional information regarding these matters. The Company believes that the likelihood of payment under its other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception.

Common Stock and Stock Compensa

Common Stock and Stock Compensation	12 Months Ended
	Dec. 31, 2016
Class of Stock [Line Items]
Common Stock [Text Block]	COMMON STOCK Stock Issued In May and August 2016, Southern Company issued an aggregate of 50.8 million shares of common stock in underwritten offerings for an aggregate purchase price of approximately $2.5 billion . Of the 50.8 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and related transaction costs, to fund a portion of the purchase price for the SNG investment and related transaction costs, and for other general corporate purposes. During the fourth quarter 2016, Southern Company issued approximately 8.0 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $381 million , net of $3 million in fees and commissions. In addition, during 2016 , Southern Company issued approximately 20 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $874 million . Shares Reserved At December 31, 2016 , a total of 94 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 94 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, 2016 . Stock-Based Compensation Stock-based compensation primarily in the form of 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, 2016 , there were 5,229 current and former employees participating in the stock option and performance share unit programs. In conjunction with the Merger, stock-based compensation in the form of Southern Company restricted stock and performance share units was also granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan. 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. 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 Expected volatility 14.6% Expected term (in years) 5 Interest rate 1.5% Dividend yield 4.9% Weighted average grant-date fair value $2.20 Southern Company's activity in the stock option program for 2016 is summarized below: Shares Subject to Option Weighted Average Exercise Price Outstanding at December 31, 2015 35,749,906 $ 40.96 Exercised 11,120,613 40.26 Cancelled 43,429 41.38 Outstanding at December 31, 2016 24,585,864 $ 41.28 Exercisable at December 31, 2016 21,133,320 $ 41.26 The number of stock options vested, and expected to vest in the future, as of December 31, 2016 was not significantly different from the number of stock options outstanding at December 31, 2016 as stated above. As of December 31, 2016 , the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years , respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $195 million and $168 million , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , total compensation cost for stock option awards recognized in income was $3 million , $6 million , and $27 million , respectively, with the related tax benefit also recognized in income of $1 million , $2 million , and $10 million , respectively. As of December 31, 2016 , 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, 2016 , 2015 , and 2014 was $120 million , $48 million , and $125 million , respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $46 million , $19 million , and $48 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2016 , 2015 , and 2014 was $448 million , $154 million , and $400 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. 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 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, 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 2016 2015 2014 Expected volatility 15.0% 12.9% 12.6% Expected term (in years) 3 3 3 Interest rate 0.8% 1.0% 0.6% Annualized dividend rate (*) N/A N/A $2.03 Weighted average grant-date fair value $45.06 $46.38 $37.54 N/A - Not applicable (*) 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. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.87 and $47.75 , respectively. Total unvested performance share units outstanding as of December 31, 2015 were 2,480,392 . During 2016 , 1,717,167 performance share units were granted, 937,121 performance share units were vested, and 35,899 performance share units were forfeited, resulting in 3,224,539 unvested performance share units outstanding at December 31, 2016 . No shares were issued in January 2017 for the three -year performance and vesting period ended December 31, 2016 . For the years ended December 31, 2016 , 2015 , and 2014 , total compensation cost for performance share units recognized in income was $96 million , $88 million , and $33 million , respectively, with the related tax benefit also recognized in income of $37 million , $34 million , and $13 million , respectively. As of December 31, 2016 , $32 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months . Southern Company Gas Restricted Stock Awards At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company's restricted stock units (RSU). Under the terms of the RSU awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three -year vesting schedule of the award being replaced. Southern Company issued 742,461 RSUs with a grant-date fair value of $53.83 , based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration. As of December 31, 2016, total compensation cost and related tax benefit for RSUs recognized in income was $13 million and $4 million , respectively. As of December 31, 2016, $12 million of total unrecognized compensation cost related to RSUs is expected to be recognized over a weighted-average period of approximately 20 months . Southern Company Gas Change in Control Awards Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares). The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance. As of December 31, 2016, total compensation cost and related tax benefit for the change in control awards recognized in income was immaterial. As of December 31, 2016, approximately $20 million of total unrecognized compensation cost related to change in control awards is expected to be recognized over a weighted-average period of approximately 23 months . Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted EPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted EPS were as follows: Average Common Stock Shares 2016 2015 2014 (in millions) As reported shares 951 910 897 Effect of options and performance share award units 7 4 4 Diluted shares 958 914 901 Prior to the adoption of ASU 2016-09, the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all "in the money" outstanding share based awards. In accordance with the new guidance, no prior year information was adjusted. Stock options and performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial as of December 31, 2016 and 2015 . Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2016 , 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 primarily in the form of Southern Company 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, 2016 , there were 865 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. The weighted average grant-date fair value of stock options granted during 2014 derived using the Black-Scholes stock option pricing model was $2.20 . The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2016 , 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, 2016 , 2015 , and 2014 was $21 million , $8 million , and $21 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $8 million , $3 million , and $8 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2016 , the aggregate intrinsic value for the options outstanding and options exercisable was $30 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. 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, 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, 2016 , 2015 , and 2014, employees of the Company were granted performance share units of 249,065 , 214,709 , and 176,070 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2016, 2015, and 2014, 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 $45.15 , $46.42 , and $37.54 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.86 and $47.78 , respectively. For the years ended December 31, 2016 , 2015 , and 2014, total compensation cost for performance share units recognized in income was $15 million , $13 million , and $5 million , respectively, with the related tax benefit also recognized in income of $6 million , $5 million , and $2 million , respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2016 , $3 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months .
Georgia Power [Member]
Class of Stock [Line Items]
STOCK COMPENSATION	STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units 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, 2016 , there were 990 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. The weighted average grant-date fair value of stock options granted during 2014 derived using the Black-Scholes stock option pricing model was $2.20 . The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2016 , 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, 2016 , 2015 , and 2014 was $18 million , $9 million , and $19 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $7 million , $4 million , and $7 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2016 , the aggregate intrinsic value for the options outstanding and options exercisable was $46 million and $41 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. 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, 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, 2016 , 2015 , and 2014 , employees of the Company were granted performance share units of 261,434 , 236,804 , and 176,224 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2016, 2015 , and 2014 , 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 $45.17 , $46.41 , and $37.54 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.84 and $47.78 , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , total compensation cost for performance share units recognized in income was $15 million , $15 million , and $6 million , respectively, with the related tax benefit also recognized in income of $6 million , $6 million , and $2 million , respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2016 , $4 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months .
Gulf Power [Member]
Class of Stock [Line Items]
STOCK COMPENSATION	STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units 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, 2016 , there were 184 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. The weighted average grant-date fair value of stock options granted during 2014 derived using the Black-Scholes stock option pricing model was $2.20 . The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2016 , 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, 2016 , 2015, and 2014 was $3 million , $2 million , and $5 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1 million for the years ended December 31, 2016 and 2015 and $2 million for 2014. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2016 , the aggregate intrinsic value for the options outstanding and options exercisable was $6 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. 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, 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, 2016 , 2015 , and 2014 , employees of the Company were granted performance share units of 57,333 , 48,962 , and 37,829 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2016 , 2015 , and 2014 , 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 $45.18 , $46.38 , and $37.54 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.83 and $47.75 , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , total compensation cost for performance share units recognized in income was $3 million , $2 million , and $1 million , respectively. The related tax benefit also recognized in income was $1 million in 2016 and 2015 and immaterial in 2014. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2016 , $2 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months .
Mississippi Power [Member]
Class of Stock [Line Items]
STOCK COMPENSATION	STOCK COMPENSATION Stock-Based Compensation Stock-based compensation primarily in the form of Southern Company performance share units 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, 2016 , there were 220 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. The weighted average grant-date fair value of stock options granted during 2014 derived using the Black-Scholes stock option pricing model was $2.20 . The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2016 , 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, 2016 , 2015 , and 2014 was $4 million , $3 million , and $5 million , respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $2 million , $1 million , and $2 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2016 , the aggregate intrinsic value for the options outstanding and options exercisable was $6 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. 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, 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, 2016 , 2015 , and 2014 , employees of the Company were granted performance share units of 62,435 , 53,909 , and 49,579 , respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2016 , 2015 , and 2014 , 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 $45.17 , $46.41 , and $37.54 , respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.84 and $47.77 , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , total compensation cost for performance share units recognized in income was $4 million , $4 million , and $2 million , respectively, with the related tax benefit also recognized in income of $1 million , $2 million , and $1 million , respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2016 , $1 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months .
Southern Company Gas [Member]
Class of Stock [Line Items]
STOCK COMPENSATION	STOCK COMPENSATION Stock-Based Compensation Successor At the effective time of the Merger, each share of Southern Company Gas common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the Merger: • Southern Company Gas' outstanding restricted stock units, restricted stock awards, and non-employee director stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share; • Southern Company Gas' outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options; and • each outstanding award of a performance share unit was converted into an award of Southern Company's restricted stock units (RSUs). In conjunction with the Merger, stock-based compensation, in the form of Southern Company restricted stock and performance share units, was granted to certain executives of the Company through the Southern Company Omnibus Incentive Compensation Plan. Southern Company Restricted Stock Awards Under the terms of the RSU awards, the employees received a specified number of RSUs that vest when the employees have satisfied the requisite service period(s) at which time the employee receives Southern Company common stock. The terms of the award require the employee to be continuously employed through the original three -year vesting schedule of the award being replaced. For the successor period ended December 31, 2016 , employees of the Company were granted 742,461 RSUs. The grant-date fair value of the RSUs granted was $53.83 , based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration. The remaining fair value of $12 million will be recognized as compensation expense on a straight-line basis over the remaining vesting period. The compensation cost related to the grant of RSUs to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. For the successor period of July 1, 2016 through December 31, 2016 , total compensation cost for RSUs recognized in income was $13 million , wi th the related tax benefit also recognized in income of $4 million . As of December 31, 2016 , $12 million of total unrecognized compensation cost related to RSUs will be recognized over a weighted-average period of approximately 20 months . See "Performance Share Unit Awards" herein for additional information. Change in Control Awards Southern Company awarded performance share units to certain employees remaining with the Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change-in-control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change-in-control benefit will vest and be issued one-third each year as long as the employee remains in service with the Company, or any of its affiliates, at each vest date. In addition to the change-in-control benefit, Southern Company common stock could be issued to the employees at the end of a performance period with the number of shares issued ranging from 0% to 100% of the target number of performance share units granted, based on achievement of certain Southern Company common stock price metrics, as well as performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares). The change-in-control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change-in-control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance. For the successor period July 1, 2016 through December 31, 2016 , total compensation cost for the change-in-control awards recognized in income was $4 million , with less than $1 million related tax benefit recognized in income. The compensation cost related to the grant of Southern Company change-in-control benefit and achievement shares to the Company's employees are recognized in the Company's financial statements with a corresponding credit to a liability or equity, representing a capital contribution from Southern Company, respectively. As of December 31, 2016 , $20 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 23 months . Predecessor For the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the employees of Southern Company Gas and subsidiaries participated in the AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated. The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provided for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards, and other stock-based awards to officers and key employees. Under the AGL Resources Inc. Omnibus Performance Incentive Plan, as of December 31, 2015 , the number of shares that were issuable upon exercise of outstanding stock options, warrants, and rights was 359,586 shares. Under the Long-Term Incentive Plan (1999), as of December 31, 2015 , the number of shares that were issuable upon exercise of outstanding stock options, warrants, and rights was 80,600 shares. The maximum number of shares that were available for future issuance under the AGL Resources Inc. Omnibus Performance Incentive Plan was 3,513,992 shares, which included 1,514,116 shares previously available under the Nicor Inc. 2006 Long-Term Incentive Plan, as amended, pursuant to New York Stock Exchange rules. Effective July 1, 2016, all Southern Company Gas shares of stock were canceled and/or converted as a result of the Merger. No further grants will be made from the Long-Term Incentive Plan (1999) or the AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated. For the predecessor periods, the Company recognized stock-based compensation expense for its stock-based awards over the requisite service period based on the estimated fair value at the date of grant for its stock-based awards using the modified prospective method. These stock awards included: stock options, stock and restricted stock awards, and performance units (restricted stock units, performance share units, and performance cash units). Performance-based stock awards and performance units contained market and performance conditions. Stock options, restricted stock awards, and performance units also contained a service condition. The Company estimated forfeitures over the requisite service period when recognizing compensation expense. These estimates were adjusted to the extent that actual forfeitures differ, or were expected to materially differ, from such estimates. Excess tax benefits were reported as a financing cash inflow. The difference between the proceeds from the exercise of the Company's stock-based awards and the par value of the stock was recorded within additional paid-in capital. Southern Company Gas granted stock awards with a grant price that was equal to the fair market value on the date of the grant. Fair market value was defined under the terms of the applicable plans as the closing price per share of Southern Company Gas' common stock on the grant date. For the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , total compensation cost for cash and stock-based awards recognized in income was $24 million , $40 million , and $24 million , respectively, with related tax benefits also recognized in income, which were immaterial. Incentive and Nonqualified Stock Options The stock options that the Company granted prior to the Merger had a three -year vesting period and expired ten years after the date of grant. The exercise price for stock options granted equaled the stock price of Southern Company Gas common stock on the date of grant. Participants realized value from option grants only to the extent that the fair market value of the Company's common stock on the date of exercise of the option exceeded the fair market value of the common stock on the date of the grant. No stock options have been issued under the plan since 2009. The Company used shares purchased under its 2006 share repurchase program to satisfy exercises to the extent that repurchased shares were available. Otherwise, the Company issued new shares from its authorized common stock. The Company measured compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. For the predecessor period ended December 31, 2015 , the Company had no unrecognized compensation costs related to stock options. Cash received from stock option exercises for the predecessor periods ended June 30, 2016 and December 31, 2015 were less than $1 million and $5 million , respectively, and the income tax benefit from stock option exercises was immaterial for both periods. For the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the total intrinsic value of options exercised was $3 million , $13 million , and $4 million , respectively. Effective July 1, 2016, all of the Company's outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options. Restricted Stock Units A restricted stock unit was an award that represented the opportunity to receive a specified number of shares of the Company's common stock, subject to the achievement of certain pre-established performance criteria. For the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the Company granted 25,166 , 47,546 , and 44,272 , respectively, of restricted stock units (including dividends) to certain employees. At the effective time of the Merger, all 65,042 restricted stock units outstanding were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share. Performance Share Unit Awards A performance share unit award represented the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. For the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the Company granted performance share unit awards to certain officers. The Company's 2016 and 2015 performance share units had two performance measures. One measure, which accounted for 75% , related to the Company's total shareholder return relative to a group of peer companies. The second measure, which accounted for 25% , related to the Company's earnings per share, excluding wholesale gas services, over the three -year performance period. The 2014 performance share units were measured entirely based on the Company's total shareholder return relative to a group of peer companies. At the effective time of the Merger, each outstanding performance share unit was converted into an award of Southern Company's restricted stock units. The conversion ratio was the product of (i) the greater of (a) 125% of the number of units underlying such award based on target level achievement of all relevant performance goals and (b) the number of units underlying such award based on the actual level of achievement of all relevant performance goals against target and (ii) an exchange ratio based on the Merger consideration of $66 per share as compared to the volume-weighted average price per share of Southern Company common stock. The resulting Southern Company restricted stock units will follow the vesting schedule and payment terms, and otherwise be issued on similar terms and conditions, as were applicable to such performance share unit awards, subject to certain exceptions. See "Southern Company Restricted Stock Awards" for additional information. Stock and Restricted Stock Awards The compensation cost of both stock awards and restricted stock awards was equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions were used to value the awards. The Company referred to restricted stock as an award of Company common stock subject to time-based vesting or achievement of performance measures. Prior to vesting, restricted stock awards were subject to certain transfer restrictions and forfeiture upon termination of employment. Restricted Stock Awards — Employees Total unvested restricted stock awards outstanding as of December 31, 2015 were 398,832 . During 2016, 303,618 restricted stock awards were granted, 699,960 restricted stock awards were vested, and 2,466 restricted stock awards were forfeited. At the effective time of the Merger, Southern Company Gas' outstanding restricted stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share.

Nuclear Insurance

Nuclear Insurance	12 Months Ended
	Dec. 31, 2016
Nuclear Insurance [Line Items]
NUCLEAR INSURANCE	NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $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 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 Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2016 under the NEIL policies would be $53 million and $82 million , respectively. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
Alabama Power [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 $13.4 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $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 maximum annual assessments for the Company as of December 31, 2016 under the NEIL policies would be $53 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 $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $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, and has elected a 12-week deductible waiting period for each facility. A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for the Company as of December 31, 2016 under the NEIL policies would be $82 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, 2016
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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 338 $ 333 $ — $ — $ 671 Interest rate derivatives — 14 — — 14 Nuclear decommissioning trusts: (c) Domestic equity 589 73 — — 662 Foreign equity 48 168 — — 216 U.S. Treasury and government agency securities — 92 — — 92 Municipal bonds — 73 — — 73 Corporate bonds 22 310 — — 332 Mortgage and asset backed securities — 183 — — 183 Private equity — — — 20 20 Other 11 15 — — 26 Cash equivalents 1,172 — — — 1,172 Other investments 9 — 1 — 10 Total $ 2,189 $ 1,261 $ 1 $ 20 $ 3,471 Liabilities: Energy-related derivatives (a)(b) $ 345 $ 285 $ — $ — $ 630 Interest rate derivatives — 29 — — 29 Foreign currency derivatives — 58 — — 58 Contingent consideration — — 18 — 18 Total $ 345 $ 372 $ 18 $ — $ 735 (a) Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives exclude cash collateral of $62 million . (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under " Nuclear Decommissioning " for additional information. 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. Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under " Nuclear Decommissioning " for additional information. Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to pay generation-based payments to the seller over a 10 -year period beginning at the commercial operation date. The obligation is measured at fair value using significant inputs such as forecasted facility generation in MW-hours, a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any change arising from forecasted generation is expected to be immaterial. "Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions. As of December 31, 2016 and 2015 , 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, 2016 $ 20 $ 25 Not Applicable Not Applicable As of December 31, 2015 $ 17 $ 28 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 10 years . As of December 31, 2016 and 2015 , 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: 2016 $ 45,080 $ 46,286 2015 $ 27,216 $ 27,913 The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, Southern Company Gas, and Nicor Gas.
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, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 20 $ — $ — $ 20 Nuclear decommissioning trusts: (*) Domestic equity 385 72 — — 457 Foreign equity 48 47 — — 95 U.S. Treasury and government agency securities — 21 — — 21 Corporate bonds 22 146 — — 168 Mortgage and asset backed securities — 19 — — 19 Private equity — — — 20 20 Other — 10 — — 10 Cash equivalents 262 — — — 262 Total $ 717 $ 335 $ — $ 20 $ 1,072 Liabilities: Energy-related derivatives $ — $ 9 $ — $ — $ 9 (*) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. 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. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. See Note 1 under "Nuclear Decommissioning" for additional information. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. As of December 31, 2016 and 2015 , 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, 2016 $ 20 $ 25 Not Applicable Not Applicable As of December 31, 2015 $ 17 $ 28 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, 2016 and 2015 , 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: 2016 $ 7,092 $ 7,544 2015 $ 6,849 $ 7,192 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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 44 $ — $ 44 Interest rate derivatives — 2 — 2 Nuclear decommissioning trusts: (*) Domestic equity 204 1 — 205 Foreign equity — 121 — 121 U.S. Treasury and government agency securities — 71 — 71 Municipal bonds — 73 — 73 Corporate bonds — 164 — 164 Mortgage and asset backed securities — 164 — 164 Other 11 5 — 16 Total $ 215 $ 645 $ — $ 860 Liabilities: Energy-related derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 3 — 3 Total $ — $ 11 $ — $ 11 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. 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. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information. As of December 31, 2016 and 2015 , 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: 2016 $ 10,516 $ 11,034 2015 $ 10,145 $ 10,480 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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 20 $ — $ — $ 20 Energy-related derivatives — 5 — 5 Total $ 20 $ 5 $ — $ 25 Liabilities: Energy-related derivatives $ — $ 29 $ — $ 29 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 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, 2016 and 2015 , 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: 2016 $ 1,074 $ 1,097 2015 $ 1,303 $ 1,339 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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 3 $ — $ 3 Interest rate derivatives — 3 — 3 Cash equivalents 206 — — 206 Total $ 206 $ 6 $ — $ 212 Liabilities: Energy-related derivatives $ — $ 10 $ — $ 10 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 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, 2016 and 2015 , 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: 2016 $ 2,979 $ 2,922 2015 $ 2,537 $ 2,413 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, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 21 $ — $ 21 Interest rate derivatives — 1 — 1 Cash equivalents 628 — — 628 Total $ 628 $ 22 $ — $ 650 Liabilities: Energy-related derivatives $ — $ 5 $ — $ 5 Foreign currency derivatives — 58 — 58 Contingent consideration — — 18 18 Total $ — $ 63 $ 18 $ 81 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 Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 9 for additional information on how these derivatives are used. The Company has contingent payment obligations related to certain acquisitions whereby the Company is obligated to pay generation-based payments to the seller over a 10 -year period beginning at the commercial operation date. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any change arising from forecasted generation is expected to be immaterial. As of December 31, 2016 and 2015 , 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: 2016 $ 5,628 $ 5,691 2015 $ 3,122 $ 3,117 The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Company.
Southern Company Gas [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. See Note 1 for additional information. As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using (a)(b) Successor – As of December 31, 2016 Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives $ 338 $ 239 $ — $ — $ 577 Liabilities: Energy-related derivatives $ 345 $ 224 $ — $ — $ 569 (a) Energy-related derivatives excludes $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $62 million . 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 (a)(b) Predecessor – As of December 31, 2015 Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives $ 53 $ 113 $ — $ — $ 166 Interest rate derivatives — 9 — — 9 Total $ 53 $ 122 $ — $ — $ 175 Liabilities: Energy-related derivatives $ 63 $ 46 $ — $ — $ 109 (a) Energy-related derivatives excludes $10 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $96 million . Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded financial products for natural gas, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard OTC products that are valued using observable market data and assumptions commonly used by market participants. See Note 10 for additional information on how these derivatives are used. Debt The Company's long-term debt is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. The Company amortizes the fair value adjustments over the lives of the respective bonds. The following table presents the carrying amount and fair value of the Company's long-term debt as of December 31: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: Successor – As of December 31, 2016 $ 5,281 $ 5,491 Predecessor – As of December 31, 2015 $ 3,820 $ 4,066 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, 2016
Derivative [Line Items]
DERIVATIVES	DERIVATIVES The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under " Financial Instruments " for additional information. Energy-Related Derivatives Southern Company and certain subsidiaries enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas uses storage and transportation capacity contracts to manage market price risks. Southern Company Gas purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price Southern Company Gas will receive in the future, resulting in a positive net adjusted operating margin. Southern Company Gas uses New York Mercantile Exchange (NYMEX) futures and over-the-counter (OTC) contracts to sell natural gas at that future price to substantially protect the adjusted operating margin ultimately realized when the stored natural gas is sold. Southern Company Gas also enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. Southern Company Gas uses NYMEX futures and OTC contracts to capture the price differential between the locations served by the capacity in order to substantially protect the adjusted operating margin ultimately realized when natural gas is physically flowed between the delivery points. These contracts generally meet the definition of derivatives, but are not designated as hedges for accounting purposes. Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income. Energy-related derivative contracts are accounted for under one of three methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. • Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. • Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 500 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 2022 for derivatives not designated as hedges. In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 9 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, 2017 are $17 million for Southern Company. Interest Rate Derivatives Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 80 3-month LIBOR 2.32% December 2026 $ — Cash Flow Hedges of Existing Debt 900 1-month LIBOR 0.79% March 2018 3 Fair Value Hedges of Existing Debt 250 1.30% 3-month LIBOR + 0.17% August 2017 — 250 5.40% 3-month LIBOR + 4.02% June 2018 — 500 1.95% 3-month LIBOR + 0.76% December 2018 (2 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 1 300 2.75% 3-month LIBOR + 0.92% June 2020 1 1,500 2.35% 1-month LIBOR + 0.87% July 2021 (18 ) Derivatives not Designated as Hedges 47 (a,b) 3-month LIBOR 2.21% January 2017 (c) 1 Total $ 4,027 $ (14 ) (a) Swaption at RE Roserock LLC. See Note 12 for additional information. (b) Amortizing notional amount. (c) Represents the mandatory settlement date. Settlement amount was based on a 15 -year amortizing swap. The estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the next 12 -month period ending December 31, 2017 total $(21) million . Deferred gains and losses are expected to be amortized into earnings through 2046 . Foreign Currency Derivatives Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2016 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ (34 ) 564 3.78% 500 1.85% June 2026 (24 ) Total $ 1,241 € 1,100 $ (58 ) The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12 -month period ending December 31, 2017 total $(25) million . Derivative Financial Statement Presentation and Amounts Southern Company and its subsidiaries enter into derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. At December 31, 2016 , fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015 , the fair value amounts of derivative instruments were presented gross on the balance sheets. At December 31, 2016 and 2015 , the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 73 $ 27 $ 3 $ 130 Other deferred charges and assets/Other deferred credits and liabilities 25 33 — 87 Total derivatives designated as hedging instruments for regulatory purposes $ 98 $ 60 $ 3 $ 217 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 23 $ 7 $ 3 $ 2 Interest rate derivatives: Other current assets/Liabilities from risk management activities, net of collateral 12 1 19 23 Other deferred charges and assets/Other deferred credits and liabilities 1 28 — 7 Foreign currency derivatives: Other current assets/Liabilities from risk management activities, net of collateral — 25 — — Other deferred charges and assets/Other deferred credits and liabilities — 33 — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 36 $ 94 $ 22 $ 32 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 489 $ 483 $ 1 $ 1 Other deferred charges and assets/Other deferred credits and liabilities 66 81 — — Interest rate derivatives: Other current assets/Liabilities from risk management activities, net of collateral 1 — 3 — Total derivatives not designated as hedging instruments $ 556 $ 564 $ 4 $ 1 Gross amounts recognized $ 690 $ 718 $ 29 $ 250 Gross amounts offset (a) $ (462 ) $ (524 ) $ (15 ) $ (15 ) Net amounts recognized in the Balance Sheets (b) $ 228 $ 194 $ 14 $ 235 (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016 . (b) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet. At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (a) Other regulatory assets, current $ (16 ) $ (130 ) Other regulatory liabilities, current $ 56 $ 3 Other regulatory assets, deferred (19 ) (87 ) Other regulatory liabilities, deferred 12 — Total energy-related derivative gains (losses) (b) $ (35 ) $ (217 ) $ 68 $ 3 (a) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet. (b) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million as of December 31, 2016 . For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Amount Derivative Category 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Energy-related derivatives $ 18 $ — $ — Depreciation and amortization $ 2 $ — $ — Cost of natural gas (1 ) — — Interest rate derivatives (180 ) (22 ) (16 ) Interest expense, net of amounts capitalized (18 ) (9 ) (8 ) Foreign currency derivatives (58 ) — — Interest expense, net of amounts capitalized (13 ) — — Other income (expense), net (*) (82 ) — — Total $ (220 ) $ (22 ) $ (16 ) $ (112 ) $ (9 ) $ (8 ) (*) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows: Derivatives in Fair Value Hedging Relationships Gain (Loss) Derivative Category Statements of Income Location 2016 2015 2014 (in millions) Interest rate derivatives: Interest expense, net of amounts capitalized $ (21 ) $ 2 $ (3 ) For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt. There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Derivatives Not Designated as Hedging Instruments Unrealized Gain (Loss) Recognized in Income Amount Derivative Category Statements of Income Location 2016 2015 2014 (in millions) Energy-related derivatives Wholesale electric revenues $ 2 $ (5 ) $ 6 Fuel — 3 (4 ) Natural gas revenues (*) 33 — — Cost of natural gas 3 — — Total $ 38 $ (2 ) $ 2 (*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the period ended December 31, 2016 . For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2016 , the fair value of derivative liabilities with contingent features was immaterial. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial 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 maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company may be required to deposit cash into these accounts. At December 31, 2016 , cash collateral held on deposit in broker margin accounts was $62 million . Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's exposure to counterparty credit risk. Southern Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, Southern Company does 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, including commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. Energy-related derivative contracts are accounted for under one of two methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the energy cost recovery clause. • Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 74 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, 2016 , there were no interest rate derivatives outstanding. The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2017 are $6 million . The Company has deferred gains and losses that are expected to be amortized into earnings through 2035. Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016 , fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015 , the fair value amounts of derivative instruments were presented gross on the balance sheets. At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected on the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 13 $ 5 $ 1 $ 40 Other deferred charges and assets/Other deferred credits and liabilities 7 4 — 15 Total derivatives designated as hedging instruments for regulatory purposes $ 20 $ 9 $ 1 $ 55 Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets/Other current liabilities $ — $ — $ — $ 15 Gross amounts recognized $ 20 $ 9 $ 1 $ 70 Gross amounts offset $ (8 ) $ (8 ) $ (1 ) $ (1 ) Net amounts recognized in the Balance Sheets (*) $ 12 $ 1 $ — $ 69 (*) At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet. Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2016 and 2015 . At December 31, 2016 and 2015 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (1 ) $ (40 ) Other current liabilities $ 8 $ 1 Other regulatory assets, deferred — (15 ) Other regulatory liabilities, deferred 4 — Total energy-related derivative gains (losses) $ (1 ) $ (55 ) $ 12 $ 1 (*) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet. For the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Interest rate derivatives $ (3 ) $ (7 ) $ (8 ) Interest expense, net of amounts capitalized $ (6 ) $ (3 ) $ (3 ) There was no material ineffectiveness recorded in earnings for any period presented. The pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material for any year presented. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2016 , the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2016 , the Company's collateral posted in these accounts was not material. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
Georgia Power [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 net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity prices. The Company manages a fuel-hedging program through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. At December 31, 2016 and 2015, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Through December 31, 2015, the Company's fuel-hedging program had a time horizon up to 24 months . Effective January 1, 2016, the Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48 -month time horizon. Energy-related derivative contracts are accounted for under one of two methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery mechanism. • Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 155 million mmBtu, all of which expire by 2020 , 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 3 million mmBtu for the Company. Interest Rate Derivatives The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. At December 31, 2016, there were no cash flow hedges outstanding. Derivatives related to fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains and losses and the hedged items' fair value gains and losses attributable to interest rate risk are both recorded directly to earnings, providing an offset, with any differences representing ineffectiveness. At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Fair Value Hedges of Existing Debt $ 250 5.40% 3-month LIBOR + 4.02% June 2018 $ — 500 1.95% 3-month LIBOR + 0.76% December 2018 (2 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 1 Total $ 950 $ (1 ) The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2017 total $4 million . Deferred gains and losses related to interest rate derivative settlements of cash flow hedges are expected to be amortized into earnings through 2037 . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016, fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015, the fair value amounts of derivative instruments were presented gross on the balance sheets. At December 31, 2016 and 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 30 $ 1 $ 2 $ 12 Other deferred charges and assets/Other deferred credits and liabilities 14 7 — 3 Total derivatives designated as hedging instruments for regulatory purposes $ 44 $ 8 $ 2 $ 15 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ 2 $ — $ 5 $ — Other deferred charges and assets/Other deferred credits and liabilities — 3 — 6 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 2 $ 3 $ 5 $ 6 Gross amounts recognized $ 46 $ 11 $ 7 $ 21 Gross amounts offset $ (8 ) $ (8 ) $ (6 ) $ (6 ) Net amounts recognized in the Balance Sheets (*) $ 38 $ 3 $ 1 $ 15 (*) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet. Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2016 and 2015 . At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ — $ (12 ) Other regulatory liabilities, current $ 29 $ 2 Other regulatory assets, deferred — (3 ) Other deferred credits and liabilities 7 — Total energy-related derivative gains (losses) $ — $ (15 ) $ 36 $ 2 (*) At December 31, 2016 , the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented gross on the balance sheet. For the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Interest rate derivatives $ — $ (15 ) $ (8 ) Interest expense, net of amounts capitalized $ (4 ) $ (3 ) $ (3 ) For the years ended December 31, 2016 and 2015 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for the Company. Furthermore, the pre-tax effect of interest rate derivatives designated as fair value hedging instruments on the Company's statements of income were offset by changes to the carrying value of long-term debt. The gains and losses related to interest rate derivative settlements of fair value hedges are recorded directly to earnings. There was no 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, 2016 , the Company's collateral posted with its derivative counterparties was immaterial. At December 31, 2016 , the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial. 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 net basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. Energy-related derivative contracts are accounted for under one of three methods: • Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause. • Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. • Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 51 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, 2016 , 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 $ — The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2017 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2026 . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016 , fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015 , the fair value amounts of derivative instruments were presented gross on the balance sheets. At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Liabilities from risk management activities $ 4 $ 12 $ — $ 49 Other deferred charges and assets/Other deferred credits and liabilities 1 17 — 51 Total derivatives designated as hedging instruments for regulatory purposes $ 5 $ 29 $ — $ 100 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Liabilities from risk management activities — — 1 — Gross amounts recognized $ 5 $ 29 $ 1 $ 100 Gross amounts offset $ (4 ) $ (4 ) $ — $ — Net amounts recognized in the Balance Sheets (*) $ 1 $ 25 $ 1 $ 100 (*) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet. Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2016 and 2015 . At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (9 ) $ (49 ) Other regulatory liabilities, current $ 1 $ — Other regulatory assets, deferred (16 ) (51 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (25 ) $ (100 ) $ 1 $ — (*) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet. For the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Statements of Income Location 2016 2015 2014 (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, 2016 , 2015 , and 2014 , 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, 2016 , the Company's collateral posted with its derivative counterparties was not material. At December 31, 2016 , the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial. 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. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. Energy-related derivative contracts are accounted for under one of the following methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. • Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of operations as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 36 million mmBtu for the Company, with the longest hedge date of 2020 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions. 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, 2016 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 900 1-month LIBOR 0.79% March 2018 $ 3 The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2017 are $2 million . The Company has deferred gains and losses that are expected to be amortized into earnings through 2022 . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016 , fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with counterparties. At December 31, 2015 , the fair value amounts of derivative instruments were presented gross on the balance sheets. At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected on the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 2 $ 6 $ — $ 29 Other deferred charges and assets/Other deferred credits and liabilities 2 5 — 18 Total derivatives designated as hedging instruments for regulatory purposes $ 4 $ 11 $ — $ 47 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ 2 $ — $ — $ — Other deferred charges and assets/Other deferred credits and liabilities 1 — — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 3 $ — $ — $ — Gross amounts recognized $ 7 $ 11 $ — $ 47 Gross amounts offset $ (3 ) $ (3 ) $ — $ — Net amounts recognized in the Balance Sheets (*) $ 4 $ 8 $ — $ 47 (*) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet. Energy-related derivatives not designated as hedging instruments were immaterial for 2016 and 2015 . At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (5 ) $ (29 ) Other regulatory liabilities, current $ 1 $ — Other regulatory assets, deferred (3 ) (18 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (8 ) $ (47 ) $ 1 $ — (*) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet. For all years presented, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of operations were immaterial. For the year ended December 31, 2016, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were $3 million . For the years ended December 31, 2015 and 2014, these effects 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, 2016 , the Company's collateral posted with its derivative counterparties was immaterial. At December 31, 2016 , the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial. 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, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the consolidated balance sheets as either assets or liabilities and are presented on a net basis. See Note 8 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company has limited exposure to market volatility in energy-related commodity prices because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. Energy-related derivative contracts are accounted for under one of two methods: • Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the consolidated statements of income in the same period as the hedged transactions are reflected in earnings. • Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 27 million mmBtu, all of which expire in 2017 , which is the longest hedge date. At December 31, 2016 , the net volume of energy-related derivative contracts for power positions was 6.1 million MWs, all of which expire in 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 maximum expected volume of natural gas subject to such a feature is 3 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, 2017 is $14 million . Interest Rate Derivatives The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred. At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Derivatives not Designated as Hedges $ 47 (a.b) 3-month LIBOR 2.21% January 2017 (c) $ 1 (a) Swaption at RE Roserock LLC. (b) Amortizing notional amount. (c) Represents the mandatory settlement date. Settlement amount was based on a 15 -year amortizing swap. The Company does not have any deferred gains and losses in AOCI related to past cash flow hedges that are expected to be amortized into earnings through 2017. As such, the Company does not expect any pre-tax gains (losses) to be reclassified from AOCI to interest expense for the 12 -month period ending December 31, 2017 . Foreign Currency Derivatives The Company may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2016 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ (34 ) 564 3.78% 500 1.85% June 2026 (24 ) Total $ 1,241 € 1,100 $ (58 ) The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12 -month period ending December 31, 2017 total $(25) million . Derivative Financial Statement Presentation and Amounts The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016, fair value amounts of derivative assets and liabilities on the consolidated balance sheets are presented net to the extent that there are netting arrangements or similar agreements with counterparties. At December 31, 2015, the fair value amounts of derivative instruments were presented gross on the consolidated balance sheets. At December 31, 2016 and 2015, the fair value of energy-related, interest rate, and foreign currency derivatives reflected in the consolidated balance sheets is as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Other current liabilities $ 18 $ 4 $ 3 $ 2 Foreign currency derivatives: Other current assets/Other current liabilities — 25 — — Other deferred charges and assets/Other deferred credits and liabilities — 33 — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 18 $ 62 $ 3 $ 2 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Other current liabilities $ 3 $ 1 $ 1 $ 1 Interest rate derivatives: Other current assets/Other current liabilities 1 — 3 — Total derivatives not designated as hedging instruments $ 4 $ 1 $ 4 $ 1 Gross amounts of recognized assets and liabilities $ 22 $ 63 $ 7 $ 3 Gross amounts offset $ (5 ) $ (5 ) $ (1 ) $ (1 ) Net amounts of assets and liabilities (*) $ 17 $ 58 $ 6 $ 2 (*) At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the consolidated balance sheet. For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of energy-related, interest rate, and foreign currency derivatives designated as cash flow hedging instruments on the consolidated statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivative Category 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Energy-related derivatives $ 14 $ — $ — Amortization $ 2 $ — $ — Interest rate derivatives — — — Interest expense, net of amounts capitalized (1 ) (1 ) (1 ) Foreign currency derivatives (58 ) — — Interest expense, net of amounts capitalized (13 ) — — Other income (expense), net (82 ) — — Total $ (44 ) $ — $ — $ (94 ) $ (1 ) $ (1 ) There was no material ineffectiveness recorded in earnings for any period presented. The pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the Company's consolidated statements of income were not material for any year presented. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2016 , there was no collateral posted with the Company's derivative counterparties. At December 31, 2016 , the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial. 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 Company Gas [Member]
Derivative [Line Items]
DERIVATIVES	DERIVATIVES The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. Wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For other businesses, the Company's policy is that derivatives are to be used primarily for hedging purposes. In both cases, the Company mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to natural gas price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, gas distribution operations has limited exposure to market volatility in prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the natural gas distribution utilities' respective state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. However, the Company retains exposure to price changes that can, in a volatile energy market, be extremely material and can adversely affect the Company. The Company also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income. Energy-related derivative contracts are accounted for under one of three methods: • Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through the respective cost recovery clauses. • Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in other OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. • Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income in the period of change. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2016 , the net volume of energy-related derivative contracts for natural gas positions totaled 157 million mmBtu for the Company, together 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 and the longest non-hedge date of 2022 for derivatives not designated as hedges. For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2017 are immaterial. Interest Rate Derivatives The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. In January 2015, the Company executed $800 million in notional value of 10 -year and 30 -year fixed-rate forward-starting interest rate swaps to hedge potential interest rate volatility prior to its issuances of long-term debt in the fourth quarter 2015 and during 2016. The Company designated the forward-starting interest rate swaps, which were settled in conjunction with the debt issuances, as cash flow hedges. The Company settled $200 million of these interest rate swaps in November 2015 for an immaterial loss, $400 million upon pricing the senior notes in May 2016 at a loss of $26 million , and the remaining $200 million upon pricing the senior notes in September 2016 at a loss of $35 million . Due to the application of acquisition accounting, only $5 million of the pre-tax loss incurred and deferred in the successor period will be amortized to interest expense through 2046, which is immaterial on an annual basis. Derivative Financial Statement Presentation and Amounts The derivative contracts of the Company are subject to master netting arrangements or similar agreements and are reported net in the financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the consolidated balance sheets as follows: Asset Derivatives Liability Derivatives Successor Predecessor Successor Predecessor Derivative Category Balance Sheet Location December 31, 2016 December 31, 2015 Balance Sheet Location December 31, 2016 December 31, 2015 (in millions) (in millions) (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Assets from risk management activities – current $ 24 $ 10 Liabilities from risk management activities – current $ 3 $ 28 Other deferred charges and assets 1 — Other deferred credits and liabilities — 2 Total derivatives designated as hedging instruments for regulatory purposes $ 25 $ 10 $ 3 $ 30 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities – current $ 4 $ 3 Liabilities from risk management activities – current $ 3 $ 5 Other deferred charges and assets — — Other deferred credits and liabilities — 2 Interest rate derivatives: Assets from risk management activities – current — 9 Liabilities from risk management activities – current — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 4 $ 12 $ 3 $ 7 Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities – current $ 486 $ 741 Liabilities from risk management activities – current $ 482 $ 644 Other deferred charges and assets 66 179 Other deferred credits and liabilities 81 185 Total derivatives not designated as hedging instruments $ 552 $ 920 $ 563 $ 829 Gross amounts of recognized assets and liabilities (a)(b) $ 581 $ 942 $ 569 $ 866 Gross amounts offset in the Balance Sheet $ (435 ) $ (724 ) $ (497 ) $ (820 ) Net amounts of derivatives assets and liabilities, presented in the Balance Sheet (c) $ 146 $ 218 $ 72 $ 46 (a) The gross amounts of recognized assets and liabilities are netted on the balance sheets to the extent that there were netting arrangements with the counterparties. (b) The gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016 and $96 million as of December 31, 2015 . (c) As of December 31, 2016 and 2015, letters of credit from counterparties offset an immaterial portion of these assets under master netting arrangements. At December 31, 2016 and 2015 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Successor Predecessor Successor Predecessor Derivative Category Balance Sheet Location December 31, 2016 December 31, 2015 Balance Sheet Location December 31, 2016 December 31, 2015 (in millions) (in millions) (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (1 ) $ (15 ) Other regulatory liabilities, current $ 17 $ 15 Other regulatory assets, deferred — (2 ) Other regulatory liabilities, deferred 1 — Total energy-related derivative gains (losses) (*) $ (1 ) $ (17 ) $ 18 $ 15 (*) Fair value gains and losses included in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million as of December 31, 2016 and $19 million as of December 31, 2015 . For the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were as follows: Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Successor Predecessor Successor Predecessor Derivatives in Cash Flow Hedging Relationships July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Statements of Income Location July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) (in millions) (in millions) Energy-related derivatives $ 2 $ — Cost of natural gas $ (1 ) $ (1 ) Interest rate derivatives (5 ) (64 ) Interest expense, net of amounts capitalized — — Total derivatives in cash flow $ (3 ) $ (64 ) $ (1 ) $ (1 ) Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Predecessor Predecessor Derivatives in Cash Flow Hedging Relationships 2015 2014 Statements of Income Location 2015 2014 (in millions) (in millions) Energy-related derivatives $ 3 $ (8 ) Cost of natural gas $ (10 ) $ 4 Other operations and maintenance (1 ) 1 Interest rate derivatives — — Interest expense, net of amounts capitalized 2 — Total derivatives in cash flow $ 3 $ (8 ) $ (9 ) $ 5 There was no material ineffectiveness recorded in earnings for any period presented. For the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows: Gain (Loss) Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, Derivatives in Non-Designated Hedging Relationships Statements of Income Location 2016 2016 2015 2014 (in millions) (in millions) Energy-related derivatives Natural gas revenues (*) $ 33 $ (1 ) $ 56 $ 149 Cost of natural gas 3 (62 ) (6 ) (7 ) Total derivatives in non-designated hedging relationships $ 36 $ (63 ) $ 50 $ 142 (*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the successor periods of July 1, 2016 through December 31, 2016 and $3 million , $12 million , and $(7) million for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , respectively. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. At December 31, 2016 , the Company had no collateral posted with derivative counterparties to satisfy these arrangements. At December 31, 2016 , the fair value of derivative liabilities with contingent features was $5 million and the maximum potential collateral requirements arising from the credit-risk-related contingent features was $9 million . Generally, collateral may be provided by a guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Prior to entering into a physical transaction, the Company assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. The Company may require counterparties to pledge additional collateral when deemed necessary. Credit evaluations are conducted and appropriate internal approvals are obtained for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, the Company requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings. The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the Company's credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
ACQUISITIONS	ACQUISITIONS Southern Company Merger with Southern Company Gas Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the purchase price allocation: Southern Company Gas Purchase Price December 31, 2016 (in millions) Current assets $ 1,557 Property, plant, and equipment 10,108 Goodwill 5,967 Intangible assets 400 Regulatory assets 1,118 Other assets 229 Current liabilities (2,201 ) Other liabilities (4,742 ) Long-term debt (4,261 ) Noncontrolling interests (174 ) Total purchase price $ 8,001 The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes. The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years . The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3). The results of operations for Southern Company Gas have been included in the consolidated financial statements from the date of acquisition and consist of operating revenues of $1.7 billion and net income of $114 million . The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger. 2016 2015 Operating revenues (in millions) $ 21,791 $ 21,430 Net income attributable to Southern Company (in millions) $ 2,591 $ 2,665 Basic EPS $ 2.70 $ 2.85 Diluted EPS $ 2.68 $ 2.84 These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future. During 2016 and 2015, Southern Company recorded in its statements of income costs associated with the Merger of approximately $111 million and $41 million , respectively, of which $80 million and $27 million is included in operating expenses and $31 million and $14 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as customer rate credits and additional compensation-related expenses. Acquisition of PowerSecure On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million . As a result, PowerSecure became a wholly-owned subsidiary of Southern Company. The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The allocation of the purchase price is as follows: PowerSecure Purchase Price December 31, 2016 (in millions) Current assets $ 172 Property, plant, and equipment 46 Intangible assets 101 Goodwill 282 Other assets 4 Current liabilities (114 ) Long-term debt, including current portion (48 ) Deferred credits and other liabilities (14 ) Total purchase price $ 429 The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $282 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes. The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years . The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3). The results of operations for PowerSecure have been included in the consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented. Alliance with Bloom Energy Corporation On October 24, 2016, a subsidiary of Southern Company acquired from an affiliate of Bloom Energy Corporation (Bloom) all of the equity interests of 2016 ESA HoldCo, LLC and its subsidiary, 2016 ESA Project Company, LLC. 2016 ESA Project Company, LLC expects to acquire 50 MWs of Bloom fuel cell systems to serve commercial and industrial customers under long-term PPAs. In connection with this transaction, PowerSecure and Bloom agreed to pursue a strategic alliance to develop technology for behind-the-meter energy solutions. Investment in Southern Natural Gas On July 10, 2016, Southern Company and Kinder Morgan, Inc. entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000 -mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion . The investment in SNG is accounted for using the equity method. Acquisition of Remaining Interest in SouthStar SouthStar is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont owning the remaining 15% . In October 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million . Southern Power During 2016 and 2015 , in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC (SRP) or Southern Renewable Energy, Inc. (SRE), acquired or contracted to acquire the projects discussed below. Also, on March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in August 2015. As a result, Southern Power and the class B member are now entitled to 66% and 34% , respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. The following table presents Southern Power's acquisitions during and subsequent to the year ended December 31, 2016 . Project Facility Resource Seller; Acquisition Date Approximate Nameplate Capacity (MW) Location Southern Power Percentage Ownership Actual/Expected COD PPA Contract Period Acquisitions During the Year Ended December 31, 2016 Boulder 1 Solar SunPower Corp. 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC 20 Imperial County, CA 90 % (b) February 2016 20 years East Pecos Solar First Solar, Inc. 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower Corp. 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc. 102 Dawson County, TX 100 % Second quarter 2017 15 years Mankato (d) Natural Gas Calpine Corporation October 26, 2016 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC 74 Rutherford County, NC 90 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc. 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc. 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy Wind Global LLC 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years Acquisitions Subsequent to December 31, 2016 Bethel Wind Invenergy Wind Global LLC 276 Castro County, TX 100 % January 2017 12 years (a) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) Southern Power owns 90% , with the minority owner, Turner Renewable Energy, LLC (TRE), owning 10% . (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) Southern Power owns 90.1% , with the minority owner, Invenergy Wind Global LLC, owning 9.9% . Acquisitions During the Year Ended December 31, 2016 Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion . Including the minority owner TRE's 10% ownership interest in Calipatria and Rutherford, SunPower Corp's 49% ownership interest in Boulder 1 and Henrietta, along with the assumption of $217 million in construction debt (non-recourse to Southern Power), and Invenergy Wind Global LLC's 9.9% ownership interest in Wake Wind, the total aggregate purchase price is approximately $2.6 billion for the project facilities acquired during the year ended December 31, 2016 . The allocations of the purchase price to individual assets have not been finalized, except for Calipatria, East Pecos, Lamesa, and Rutherford, which were finalized with no changes to amounts originally reported. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: Southern Power (b)(c) $ 2,345 Noncontrolling interests (d)(e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. (b) At December 31, 2016 , $461 million is included in acquisitions payable on the balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $67 million remains payable at December 31, 2016. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. The following table presents Southern Power's acquisitions for the year ended December 31, 2015 . During the year ended December 31, 2016 , the fair values of assets and liabilities acquired for all projects listed below were finalized with no changes to amounts originally reported. Project Facility Resource Seller; Acquisition Date Approximate MW ) Location Southern Power Percentage Ownership Actual COD PPA Acquisitions for the Year Ended December 31, 2015 Desert Stateline Solar First Solar Inc. 299 (a) San Bernardino County, CA 51 % (b) From December 2015 to July 2016 20 years Garland and Garland A Solar Recurrent Energy, LLC 205 Kern County, CA 51 % (b) October and August 2016 15 years and 20 years Kay Wind Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 2015 20 years Lost Hills Blackwell Solar First Solar Inc. 33 Kern County, CA 51 % (b) April 2015 29 years Morelos Solar Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % (c) November 2015 20 years North Star Solar First Solar Inc. 61 Fresno County, CA 51 % (b) June 2015 20 years Roserock Solar Recurrent Energy, LLC November 23, 2015 160 Pecos County, TX 51 % (b) November 2016 20 years Tranquillity Solar Recurrent Energy, LLC 205 Fresno County, CA 51 % (b) July 2016 18 years (a) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (b) 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. (c) Southern Power owns 90% , with the minority owner, TRE, owning 10% . Acquisitions During the Year Ended December 31, 2015 Southern Power's aggregate purchase price for the project facilities acquired during the year ended December 31, 2015 was approximately $1.4 billion . Including the minority owner TRE's 10% ownership interest in Morelos, First Solar Inc.'s 49% ownership interest in Desert Stateline, Lost Hills Blackwell, and North Star, and Recurrent Energy, LLC's 49% ownership interest in Garland, Garland A, Roserock, and Tranquillity, the total aggregate purchase price was approximately $1.9 billion for the project facilities acquired during the year ended December 31, 2015. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2015 (in millions) CWIP $ 1,367 Property, plant, and equipment 315 Intangible assets (a) 274 Other assets 64 Accounts payable (89 ) Total purchase price $ 1,931 Funded by: Southern Power (b) $ 1,440 Noncontrolling interests (c) (d) 491 Total purchase price $ 1,931 (a) Intangible assets consist of acquired PPAs that will be amortized over 20 -year terms. The estimated amortization for future periods is approximately $14 million per year. (b) Includes approximately $195 million of contingent consideration, all of which has been paid at December 31, 2016 . (c) Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. (d) Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. Construction Projects Construction Projects Completed During 2016, in accordance with Southern Power's overall growth strategy, Southern Power completed construction of, and placed in service, the projects set forth in the table below. Total costs of construction incurred for these projects were $3.2 billion . Solar Facility Seller Approximate Nameplate Capacity ( MW ) Location Actual COD PPA Contract Period Butler CERSM, LLC and Community Energy, Inc. 103 Taylor County, GA December 2016 30 years (a) Butler Solar Farm Strata Solar Development, LLC 22 Taylor County, GA February 2016 20 years (a) Desert Stateline First Solar Development, LLC 299 (b) San Bernardino County, CA From December 2015 to July 2016 20 years Garland Recurrent Energy, LLC 185 Kern County, CA October 2016 15 years Garland A Recurrent Energy, LLC 20 Kern County, CA August 2016 20 years Pawpaw Longview Solar, LLC 30 Taylor County, GA March 2016 30 years Roserock (c) Recurrent Energy, LLC 160 Pecos County, TX November 2016 20 years Sandhills N/A 146 Taylor County, GA October 2016 25 years Tranquillity Recurrent Energy, LLC 205 Fresno County, CA July 2016 18 years (a) Affiliate PPA approved by the FERC. (b) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (c) Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. Construction Projects in Progress At December 31, 2016 , Southern Power continued construction of the East Pecos and Lamesa solar facilities that were acquired in 2016 . In addition, as part of Southern Power's acquisition of Mankato in 2016, Southern Power commenced construction of an additional 345 -MW expansion, which is fully contracted under a new 20 -year PPA. Total aggregate construction costs, excluding the acquisition costs, are expected to be $530 million to $590 million for East Pecos, Lamesa, and Mankato. At December 31, 2016, the construction costs totaled $386 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time. The following table presents Southern Power's construction projects in progress as of December 31, 2016: Project Facility Resource Approximate Nameplate Capacity (MW) Location Actual/Expected COD PPA Contract Period East Pecos Solar 120 Pecos County, TX March 2017 15 years Lamesa Solar 102 Dawson County, TX Second quarter 2017 15 years Mankato Natural Gas 345 Mankato, MN Second quarter 2019 20 years Development Projects In December 2016, as part of Southern Power's renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs across 10 wind projects expected to be placed in service between 2018 and 2020. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs. The ultimate outcome of these matters cannot be determined at this time.
Southern Power [Member]
Business Acquisition [Line Items]
ACQUISITIONS	ACQUISITIONS During 2016 and 2015 , in accordance with its overall growth strategy, the Company or one of its wholly-owned subsidiaries, SRP and SRE, acquired or contracted to acquire the projects discussed below. Also, on March 29, 2016, the Company acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in August 2015. As a result, the Company and the class B member are now entitled to 66% and 34% , respectively, of all cash distributions from Desert Stateline. In addition, the Company will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented. The following table presents the Company's acquisitions during and subsequent to the year ended December 31, 2016. Project Facility Resource Seller; Acquisition Date Approximate Nameplate Capacity ( MW ) Location Percentage Ownership Actual/Expected COD PPA Contract Period Acquisitions During the Year Ended December 31, 2016 Boulder 1 Solar SunPower 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC 20 Imperial County, CA 90 % (b) February 2016 20 years East Pecos Solar First Solar, Inc. 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc. 102 Dawson County, TX 100 % Second quarter 2017 15 years Mankato (d) Natural Gas Calpine Corporation October 26, 2016 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC 74 Rutherford County, NC 90 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc. 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc. 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years Acquisitions Subsequent to December 31, 2016 Bethel Wind Invenergy 276 Castro County, TX 100 % January 2017 12 years (a) The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) The Company owns 90% , with the minority owner, TRE, owning 10% . (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) The Company owns 90.1% , with the minority owner, Invenergy, owning 9.9% . Acquisitions During the Year Ended December 31, 2016 The Company's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion . Including the minority owner TRE's 10% ownership interest in Calipatria and Rutherford, SunPower's 49% ownership interest in Boulder 1 and Henrietta, along with the assumption of $217 million in construction debt (non-recourse to the Company), and Invenergy's 9.9% ownership interest in Wake Wind, the total aggregate purchase price is approximately $2.6 billion for the project facilities acquired during the year ended December 31, 2016 . The allocations of the purchase price to individual assets have not been finalized, except for Calipatria, East Pecos, Lamesa, and Rutherford, which were finalized with no changes to amounts originally reported. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: The Company (b) (c) $ 2,345 Noncontrolling interests (d) (e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. (b) At December 31, 2016 , $461 million is included in acquisitions payable on the consolidated balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $67 million remains payable at December 31, 2016. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. The aggregate amount of revenue recognized by the Company related to the acquisitions during 2016, included in the consolidated statement of income for 2016 , is $37 million . The amount of net income, excluding impacts of ITCs and PTCs, attributable to the Company related to the acquisitions during 2016 included in the consolidated statement of income is immaterial. The solar and wind acquisitions did not have operating revenues or net income prior to the completion of construction and the generating facility being placed in service; therefore, supplemental pro forma information as if these acquisitions occurred as of the beginning of 2016 , and for the comparable 2015 year, is not meaningful and has been omitted. However, the Mankato acquisition is an operating facility and unaudited supplemental pro forma information, as though the acquisition occurred as of the beginning of 2016 and for the comparable 2015 year, is as follows: 2016 2015 (in millions) Revenues $ 40 $ 39 Net income $ 14 $ 11 These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that may be attained in the future. The following table presents the Company's acquisitions for the year ended December 31, 2015 . During the year ended December 31, 2016 , the fair values of assets and liabilities acquired for all projects listed below were finalized with no changes to amounts originally reported. Project Facility Resource Seller; Acquisition Date Approximate MW ) Location Percentage Ownership Actual COD PPA Acquisitions for the Year Ended December 31, 2015 Desert Stateline Solar First Solar 299 (a) San Bernardino County, CA 51 % (b) From December 2015 to July 2016 20 years Garland and Garland A Solar Recurrent 205 Kern County, CA 51 % (b) October and August 2016 15 years and 20 years Kay Wind Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 2015 20 years Lost Hills Blackwell Solar First Solar 33 Kern County, CA 51 % (b) April 2015 29 years Morelos Solar Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % (c) November 2015 20 years North Star Solar First Solar 61 Fresno County, CA 51 % (b) June 2015 20 years Roserock Solar Recurrent November 23, 2015 160 Pecos County, TX 51 % (b) November 2016 20 years Tranquillity Solar Recurrent 205 Fresno County, CA 51 % (b) July 2016 18 years (a) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (b) 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. (c) The Company owns 90% , with the minority owner, TRE, owning 10% . Acquisitions During the Year Ended December 31, 2015 The Company's aggregate purchase price for the project facilities acquired during the year ended December 31, 2015 was approximately $1.4 billion . Including the minority owner TRE's 10% ownership interest in Morelos, First Solar's 49% ownership interest in Desert Stateline, Lost Hills Blackwell, and North Star, and Recurrent's 49% ownership interest in Garland, Garland A, Roserock, and Tranquillity, the total aggregate purchase price was approximately $1.9 billion for the project facilities acquired during the year ended December 31, 2015 . The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2015 (in millions) CWIP $ 1,367 Property, plant, and equipment 315 Intangible assets (a) 274 Other assets 64 Accounts payable (89 ) Total purchase price $ 1,931 Funded by: The Company (b) $ 1,440 Noncontrolling interests (c) (d) 491 Total purchase price $ 1,931 (a) Intangible assets consist of acquired PPAs that will be amortized over 20 -year terms. The estimated amortization for future periods is approximately $14 million per year. See Note 1 under "Impairment of Long-Lived Assets and Intangibles" for additional information. (b) Includes approximately $195 million of contingent consideration, all of which had been paid at December 31, 2016 . (c) Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity. (d) Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. Construction Projects Construction Projects Completed During 2016 , in accordance with its overall growth strategy, the Company completed construction of, and placed in service, the projects set forth in the table below. Total costs of construction incurred for these projects were $3.2 billion . Solar Facility Seller Approximate Nameplate Capacity ( MW ) Location Actual COD PPA Contract Period Butler CERSM, LLC and Community Energy, Inc. 103 Taylor County, GA December 2016 30 years (a) Butler Solar Farm Strata Solar Development, LLC 22 Taylor County, GA February 2016 20 years (a) Desert Stateline First Solar Development, LLC 299 (b) San Bernardino County, CA From December 2015 to July 2016 20 years Garland Recurrent 185 Kern County, CA October 2016 15 years Garland A Recurrent 20 Kern County, CA August 2016 20 years Pawpaw Longview Solar, LLC 30 Taylor County, GA March 2016 30 years Roserock (c) Recurrent 160 Pecos County, TX November 2016 20 years Sandhills N/A 146 Taylor County, GA October 2016 25 years Tranquillity Recurrent 205 Fresno County, CA July 2016 18 years (a) Affiliate PPA approved by the FERC. (b) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (c) Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. Construction Projects in Progress At December 31, 2016 , the Company continued construction of the East Pecos and Lamesa solar facilities that were acquired in 2016 . In addition, as part of the Company's acquisition of Mankato in 2016 , the Company commenced construction of an additional 345 -MW expansion, which is fully contracted under a new 20 -year PPA. Total aggregate construction costs, excluding the acquisition costs, are expected to be $530 million to $590 million for East Pecos, Lamesa, and Mankato. At December 31, 2016 , the construction costs totaled $386 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time. The following table presents the Company's construction projects in progress as of December 31, 2016: Project Facility Resource Approximate Nameplate Capacity ( MW ) Location Actual/Expected COD PPA Contract Period East Pecos Solar 120 Pecos County, TX March 2017 15 years Lamesa Solar 102 Dawson County, TX Second quarter 2017 15 years Mankato Natural Gas 345 Mankato, MN Second quarter 2019 20 years Development Projects In December 2016 , as part of the Company's renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs across 10 wind projects expected to be placed in service between 2018 and 2020 . Also in December 2016, the Company signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs. The ultimate outcome of these matters cannot be determined at this time.
Southern Company Gas [Member]
Business Acquisition [Line Items]
ACQUISITIONS	MERGER AND ACQUISITION Merger with Southern Company On July 1, 2016, the Company completed the Merger with Southern Company. A wholly-owned, direct subsidiary of Southern Company merged with and into Southern Company Gas, with the Company surviving as a wholly-owned, direct subsidiary of Southern Company. At the effective time of the Merger, each share of Southern Company Gas common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the Merger, all of the outstanding restricted stock units, restricted stock awards, non-employee director stock awards, stock options, and performance share units were either redeemed or converted into Southern Company's restricted stock units. See Note 8 for additional information. The application of the acquisition method of accounting was pushed down to the Company. The excess of the purchase price over the fair values of the Company's assets and liabilities was recorded as goodwill, which represents a different basis of accounting from the historical basis prior to the Merger. The following table presents the final purchase price allocation: Successor Predecessor New Basis Old Basis Change in Basis (in millions) (in millions) Current assets $ 1,557 $ 1,474 $ 83 Property, plant, and equipment 10,108 10,148 (40 ) Goodwill 5,967 1,813 4,154 Other intangible assets 400 101 299 Regulatory assets 1,118 679 439 Other assets 229 273 (44 ) Current liabilities (2,201 ) (2,205 ) 4 Other liabilities (4,742 ) (4,600 ) (142 ) Long-term debt (4,261 ) (3,709 ) (552 ) Contingently redeemable noncontrolling interest (174 ) (41 ) (133 ) Total purchase price/equity $ 8,001 $ 3,933 $ 4,068 Measurement period adjustments were recorded to the purchase price allocation during the fourth quarter 2016, which resulted in a net $30 million increase in goodwill to establish intangible liabilities for transportation contracts at wholesale services, partially offset by adjustments to deferred tax balances. In determining the fair value of assets and liabilities subject to rate regulation that allows recovery of costs and/or a fair return on investments, historical cost was deemed to be a reasonable proxy for fair value, as it is included in rate base or otherwise specified in regulatory recovery mechanisms. Property, plant, and equipment subject to rate regulation was reflected based on the historical gross amount of assets in service and accumulated depreciation, as they are included in rate base. For certain assets and liabilities subject to rate regulation (such as debt instruments and employee benefit obligations), the fair value adjustment was applied to historical cost with a corresponding offset to regulatory asset or liability based on the assessment of probable future recovery in rates. For unregulated assets and liabilities, fair value adjustments were applied to historical cost of natural gas for sale, property, plant, and equipment, debt instruments, and noncontrolling interest. The valuation of other intangible assets included customer relationships, trade names, and favorable/unfavorable contracts. The valuation of these assets and liabilities applied either the market approach or income approach. The market approach was utilized when prices and other relevant market information were available. The income approach, which is based on discounted cash flows, was primarily based on significant unobservable inputs (Level 3). Key estimates and inputs included forecasted profitability and cash flows, customer retention rates, royalty rates, and discount rates. The estimated fair value of deferred income taxes was determined by applying the appropriate enacted statutory tax rate to the temporary differences that arose on the differences between the financial reporting value and tax basis of the assets acquired and liabilities assumed. The excess of the purchase price over the estimated fair value of assets and liabilities of $6.0 billion was recognized as goodwill, which is primarily attributable to positioning Southern Company to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. The Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes. The Company's results for the successor period of July 1, 2016 through December 31, 2016 include a $20 million decrease in consolidated earnings comprised of $17 million of reduced revenues and $22 million of increased amortization, partially offset by lower interest expense of $19 million , as a result of the fair value adjustment of assets and liabilities in the application of acquisition accounting. Transaction costs included $18 million in rate credits provided to the customers of Elizabethtown Gas and Elkton Gas as a condition of the Merger, $3 million for financial advisory fees, legal expenses, and other Merger-related costs, including certain amounts payable upon successful completion of the Merger, and $20 million for additional compensation-related expenses, including accelerated vesting of share-based compensation expenses and change-in-control compensation charges. During the predecessor period of January 1, 2016 through June 30, 2016 , the Company recorded in its statements of income transaction costs of $56 million . Transaction costs included $31 million for financial advisory fees, legal expenses, and other Merger-related costs, including certain amounts payable upon successful completion of the Merger, which was deemed probable on June 29, 2016, and $25 million of additional compensation related expenses, including accelerated vesting of share-based compensation expenses and certain Merger-related compensation charges. The Company recorded Merger-related expenses of $44 million for the predecessor year ended December 31, 2015. The Company previously treated these costs as tax deductible since the requisite closing conditions to the Merger had not yet been satisfied. During the second quarter 2016, when the Merger became probable, the Company re-evaluated the tax deductibility of these costs and reflected any non-deductible amounts in the effective tax rate. The receipt of required regulatory approvals was conditioned upon certain terms and commitments. In connection with these regulatory approvals, certain regulatory agencies prohibited the Company from recovering goodwill and Merger-related expenses, required the Company to maintain a minimum number of employees for a set period of time to ensure that certain pipeline safety standards and the competence level of the employee workforce is not degraded, and/or required the Company to maintain its pre-Merger level of support for various social and charitable programs. The most notable terms and commitments with potential financial impacts included: • rate credits of $18 million to be paid to customers in New Jersey and Maryland; • sharing of Merger savings with customers in Georgia starting in 2020; • phasing-out the use of the Nicor name or logo by certain of the Company's gas marketing services subsidiaries in conducting non-utility business in Illinois; • reaffirming that Elizabethtown Gas would file a base rate case no later than September 1, 2016, with another base rate case no later than three years after the 2016 rate case; and • requiring Elkton Gas to file a base rate case within two years of closing the Merger. There is no restriction on the Company's other utilities' ability to file future rate cases. The rate credits to customers in New Jersey and Maryland were paid during the third and fourth quarters of 2016, respectively, and Elizabethtown Gas filed a base rate case with the New Jersey BPU on September 1, 2016. Upon completion of the Merger, the Company amended and restated its Bylaws and Articles of Incorporation, under which it now has the authority to issue no more than 110 million shares of stock consisting of (i) 100 million shares of common stock and (ii) 10 million shares of preferred stock, both categories of which have a par value of $0.01 per share. The amended and restated Articles of Incorporation do not allow any treasury shares to be held. Investment in SNG On September 1, 2016, the Company, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG pursuant to a definitive agreement between Southern Company and Kinder Morgan, Inc. on July 10, 2016, to which Southern Company assigned all rights and obligations to the Company on August 31, 2016. SNG owns a 7,000 -mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of $1.4 billion was financed by a $1.05 billion equity contribution from Southern Company and $360 million of cash paid by the Company, which was financed by a promissory note from Southern Company and repaid with a portion of the proceeds from the senior notes issued in September 2016. The purchase price of the 50% equity interest exceeded the underlying ownership interest in the net assets of SNG by approximately $700 million . This basis difference is attributable to goodwill and deferred tax assets. While the deferred tax assets will be amortized through deferred tax expense, the goodwill will not be amortized and is not required to be tested for impairment on an annual basis. See Note 4 under "Equity Method Investments" for additional information on this investment.

Segment and Related Information

Segment and Related Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting Information [Line Items]
SEGMENT AND RELATED INFORMATION	SEGMENT AND RELATED INFORMATION The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power and, as a result of closing the Merger, the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $419 million , $417 million , and $383 million in 2016 , 2015 , and 2014 , respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2016 , 2015 , and 2014 was as follows: Electric Utilities Traditional Electric Operating Companies Southern Power Eliminations Total Southern Company Gas All Other Eliminations Consolidated (in millions) 2016 Operating revenues $ 16,803 $ 1,577 $ (439 ) $ 17,941 $ 1,652 $ 463 $ (160 ) $ 19,896 Depreciation and amortization 1,881 352 — 2,233 238 31 — 2,502 Interest income 6 7 — 13 2 20 (15 ) 20 Earnings from equity method investments 2 — — 2 60 (3 ) — 59 Interest expense 814 117 — 931 81 317 (12 ) 1,317 Income taxes 1,286 (195 ) — 1,091 76 (216 ) — 951 Segment net income (loss) (a) (b) 2,233 338 — 2,571 114 (230 ) (7 ) 2,448 Total assets 72,141 15,169 (316 ) 86,994 21,853 2,474 (1,624 ) 109,697 Gross property additions 4,852 2,114 — 6,966 618 41 (1 ) 7,624 2015 Operating revenues $ 16,491 $ 1,390 $ (439 ) $ 17,442 $ — $ 152 $ (105 ) $ 17,489 Depreciation and amortization 1,772 248 — 2,020 — 14 — 2,034 Interest income 19 2 1 22 — 6 (5 ) 23 Earnings from equity method investments 1 — — 1 — (1 ) — — Interest expense 697 77 — 774 — 69 (3 ) 840 Income taxes 1,305 21 — 1,326 — (132 ) — 1,194 Segment net income (loss) (a) (b) 2,186 215 — 2,401 — (32 ) (2 ) 2,367 Total assets 69,052 8,905 (397 ) 77,560 — 1,819 (1,061 ) 78,318 Gross property additions 5,124 1,005 — 6,129 — 40 — 6,169 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 Earnings from equity method investments 1 — — 1 — (1 ) — — 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 (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $428 million ( $264 million after tax) in 2016, $365 million ( $226 million after tax) in 2015, and $868 million ( $536 million after tax) in 2014. See Note 3 under " Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate " for additional information. (c) Net of $202 million of unamortized debt issuance costs as of December 31, 2014. Also net of $488 million of deferred tax assets as of December 31, 2014. Products and Services Electric Utilities' Revenues Year Retail Wholesale Other Total (in millions) 2016 $ 15,234 $ 1,926 $ 781 $ 17,941 2015 14,987 1,798 657 17,442 2014 15,550 2,184 672 18,406 Southern Company Gas' Revenues Year Gas Gas All Other Total (in millions) 2016 $ 1,266 $ 354 $ 32 $ 1,652
Southern Company Gas [Member]
Segment Reporting Information [Line Items]
SEGMENT AND RELATED INFORMATION	SEGMENT AND RELATED INFORMATION The Company manages its business through four reportable segments - gas distribution operations (formerly referred to as distribution operations), gas marketing services (formerly referred to as retail operations), wholesale gas services (formerly referred to as wholesale services), and gas midstream operations (formerly referred to as midstream operations). The non-reportable segments are combined and presented as all other. In conjunction with the Merger, the Company changed the names of certain reportable segments to better align with its new parent company. Gas distribution operations is the largest component of the Company's business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. Wholesale gas services provides natural gas asset management and/or related logistics services for each of the Company's utilities except Nicor Gas as well as for non-affiliated companies. Additionally, this segment engages in natural gas storage and gas pipeline arbitrage and related activities. Since the acquisition of the Company's 50% interest in SNG, gas midstream operations primarily consists of the Company's gas pipeline investments, with storage and fuel operations also aggregated into this segment. The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure. After the Merger, the Company changed the segment performance measure to net income, which is utilized by its new parent company. In order to properly assess net income by segment, the Company executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor periods, the Company is unable to provide the comparable net income for those periods. Financial data for business segments for the successor period of July 1, 2016 through December 31, 2016 and for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 were as follows: Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (*) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Successor – July 1, 2016 through December 31, 2016 Operating revenues $ 1,342 $ 354 $ 24 $ 31 $ 1,751 $ 3 $ (102 ) $ 1,652 Depreciation and 185 35 1 9 230 8 — 238 Earnings from equity — — — 58 58 2 — 60 Interest expense (105 ) (1 ) (3 ) (16 ) (125 ) 44 — (81 ) Income taxes 51 7 (3 ) 16 71 5 — 76 Segment net income 77 19 — 20 116 (2 ) — 114 Gross property 561 5 1 54 621 11 — 632 Successor – Total 19,453 2,084 1,127 2,211 24,875 11,145 (14,167 ) 21,853 (*) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (*) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Predecessor – January 1, 2016 through June 30, 2016 Operating revenues $ 1,575 $ 435 $ (32 ) $ 25 $ 2,003 $ 4 $ (102 ) $ 1,905 Depreciation and 178 11 1 9 199 7 — 206 EBIT 353 109 (68 ) (6 ) 388 (60 ) — 328 Gross property additions 484 4 1 43 532 16 — 548 Predecessor – Year Ended December 31, 2015 Operating revenues $ 3,049 $ 835 $ 202 $ 55 $ 4,141 $ 11 $ (211 ) $ 3,941 Depreciation and 336 25 1 18 380 17 — 397 EBIT 581 152 110 (23 ) 820 (59 ) — 761 Gross property additions 957 7 2 27 993 34 — 1,027 Predecessor – Total 12,519 686 935 692 14,832 9,662 (9,740 ) 14,754 Predecessor – Year Ended December 31, 2014 Operating revenues $ 4,001 $ 994 $ 578 $ 88 5,661 $ 7 $ (283 ) $ 5,385 Depreciation and 317 28 1 18 364 16 — 380 EBIT 582 132 425 (17 ) 1,122 (10 ) — 1,112 Gross property additions 715 11 2 15 743 26 — 769 Predecessor – Total 12,038 670 1,402 694 14,804 9,705 (9,647 ) 14,862 (*) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. Third Party Gross Revenues Intercompany Revenues Total Gross Revenues Less Gross Gas Costs Operating Revenues (in millions) Successor – July 1, 2016 through $ 5,807 $ 333 $ 6,140 $ 6,116 $ 24 (in millions) Predecessor – January 1, 2016 through $ 2,500 $ 143 $ 2,643 $ 2,675 $ (32 ) Year Ended December 31, 2015 6,286 408 6,694 6,492 202 Year Ended December 31, 2014 10,709 718 11,427 10,849 578

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2016
Southern Company Gas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
DISCONTINUED OPERATIONS	DISCONTINUED OPERATIONS In 2014, the Company sold Tropical Shipping, which was previously reported as its own segment, to an unrelated third party. The after-tax cash proceeds and distributions from the transaction were approximately $225 million . The Company determined that the cumulative foreign earnings of Tropical Shipping would no longer be indefinitely reinvested offshore. Accordingly, the Company recognized income tax expense of $60 million , of which $31 million was recorded in the first quarter 2014, and the remaining $29 million was recorded in the third quarter 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in the repatriation of $86 million in cash. During 2014, based upon the negotiated sales price, the Company recorded a non-cash goodwill impairment charge of $19 million , for which there was no income tax benefit. Additionally, the Company recognized a total charge of $7 million in 2014 related to the suspension of depreciation and amortization on assets for which the Company was not compensated by the buyer. The components of discontinued operations recorded on the statements of income for the predecessor year ended December 31, 2014 are as follows: Year Ended December 31, 2014 (in millions) Operating revenues $ 243 Operating expenses Cost of goods sold 149 Operation and maintenance 75 Depreciation and amortization 5 Taxes other than income taxes 5 Loss on sale and goodwill impairment (*) 28 Total operating expenses 262 Operating (loss) income (19 ) (Loss) income before income taxes (19 ) Income tax expense (61 ) (Loss) income from discontinued operations, net of tax $ (80 ) (*) Primarily reflects $7 million due to the suspension of depreciation and amortization during 2014 and $19 million of goodwill attributable to Tropical Shipping that was impaired in 2014, based on the negotiated sales price.

Noncontrolling Interest

Noncontrolling Interest	12 Months Ended
	Dec. 31, 2016
Southern Power [Member]
Noncontrolling Interest [Line Items]
NONCONTROLLING INTEREST	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, and SunPower can require the Company to purchase its redeemable noncontrolling interest at fair market value until April 30, 2017. As of December 31, 2016, the carrying amounts of STR's and SunPower's noncontrolling interests were $50 million and $114 million , respectively. The following table presents the changes in redeemable noncontrolling interests for the years ended December 31: 2016 2015 2014 (in millions) Beginning balance $ 43 $ 39 $ 29 Net income attributable to redeemable noncontrolling interests 4 2 4 Distributions to redeemable noncontrolling interests (1 ) — (1 ) Capital contributions from redeemable noncontrolling interests 118 2 7 Ending balance $ 164 $ 43 $ 39 The following table presents the attribution of net income (loss) to the Company and the noncontrolling interests for the years ended December 31: 2016 2015 2014 (in millions) Net income $ 374 $ 229 $ 175 Less: Net income (loss) attributable to noncontrolling interests 32 12 (1 ) Less: Net income attributable to redeemable noncontrolling interests 4 2 4 Net income attributable to the Company $ 338 $ 215 $ 172

Capitalization

Capitalization	12 Months Ended
	Dec. 31, 2016
Debt Instrument [Line Items]
CAPITALIZATION	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, 2016 and 2015 , 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, 2016 and 2015 , 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: 2016 2015 (in millions) Senior notes $ 1,995 $ 1,810 Other long-term debt 485 829 Pollution control revenue bonds (*) 76 4 Capitalized leases 32 32 Unamortized debt issuance expense (1 ) (1 ) Total $ 2,587 $ 2,674 (*) Includes $40 million of pollution control revenue bonds classified as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. Maturities through 2021 applicable to total long-term debt are as follows: $2.6 billion in 2017 ; $3.9 billion in 2018 ; $3.2 billion in 2019 ; $1.4 billion in 2020 ; and $3.1 billion in 2021 . Bank Term Loans Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. At December 31, 2016 , Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million , $45 million , $100 million , $1.2 billion , and $380 million , respectively, of which $2.0 billion are reflected in the statements of capitalization as long-term debt and $100 million are reflected in the balance sheet as notes payable. At December 31, 2015 , Southern Company, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million , $900 million , and $400 million , respectively . In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million , one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR. In March 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion . Mississippi Power borrowed $900 million in March 2016 under the term loan agreement and the remaining $300 million in October 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans in March 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. This loan matures on April 1, 2018 and bears interest based on one-month LIBOR. In May 2016, Gulf Power entered into an 11 -month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes. In September 2016, Southern Power Company repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power Company entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes. The outstanding bank loans as of December 31, 2016 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, 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, 2016 , each of Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits. DOE Loan Guarantee Borrowings Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into 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 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 June and December 2016, Georgia Power made borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million and $125 million , respectively. The interest rate applicable to the $300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142% , both for an interest period that extends to the final maturity date of February 20, 2044. At December 31, 2016 and 2015 , Georgia Power had $2.6 billion and $2.2 billion of borrowings outstanding under the FFB Credit Facility, respectively. 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). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle 3 and 4 Agreement; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. 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 $13.3 billion of senior notes in 2016 . Southern Company issued $8.5 billion and its subsidiaries issued a total of $4.8 billion . These amounts include senior notes issued by Southern Company Gas subsequent to the Merger. The proceeds of Southern Company's issuances were used to fund a portion of the consideration for the Merger and related transaction costs and for general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs, and, for Southern Power, its growth strategy. Certain of Georgia Power's and Southern Power's issuances were allocated to eligible renewable energy expenditures. The proceeds of Southern Company Gas' issuances were primarily used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), to fund the purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar Energy Services, LLC (SouthStar), and to make a voluntary contribution to Southern Company Gas' pension plan. See Note 12 under " Southern Company – Investment in Southern Natural Gas " and " – Acquisition of Remaining Interest in SouthStar " for additional information. At December 31, 2016 and 2015 , Southern Company and its subsidiaries had a total of $33.0 billion and $19.1 billion , respectively, of senior notes outstanding. At December 31, 2016 and 2015 , Southern Company had a total of $10.3 billion and $2.4 billion , respectively, of senior notes outstanding. These amounts include senior notes due within one year. Subsequent to December 31, 2016, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2007A 5.55% Senior Notes due February 1, 2017. 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 At December 31, 2016 and 2015 , Southern Company had a total of $2.4 billion and $1.0 billion , respectively, of junior subordinated notes outstanding. In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes. In December 2016, Southern Company issued $550 million aggregate principal amount of Series 2016B Junior Subordinated Notes due March 15, 2057, which bear interest at a fixed rate of 5.50% per year up to, but not including, March 15, 2022. From, and including, March 15, 2022, the Series 2016B Junior Subordinated Notes will bear interest at a floating rate based on three-month LIBOR. The proceeds were used for general corporate purposes. Pollution Control Revenue Bonds Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2016 and 2015 , which includes pollution control revenue bonds due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. Plant Daniel Revenue Bonds In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See " Assets Subject to Lien " herein for additional information. Gas Facility Revenue Bonds Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas, is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2016 was $200 million . 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, 2016 and 2015 . Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. First Mortgage Bonds Nicor Gas, a subsidiary of Southern Company Gas, had $625 million of first mortgage bonds outstanding at December 31, 2016 . These bonds have been issued with maturities ranging from 2019 to 2038. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See " Assets Subject to Lien " herein for additional information. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt. In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2016 and 2015 of approximately $74 million and $77 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. See Note 3 under " Integrated Coal Gasification Combined Cycle " for additional information regarding the Kemper IGCC. At December 31, 2016 and 2015 , the capitalized lease obligations for Georgia Power's corporate headquarters building were $28 million and $35 million , respectively, with an annual interest rate of 7.9% for both years. At December 31, 2016 and 2015 , Alabama Power had capitalized lease obligations of $4 million and $5 million , respectively, for a natural gas pipeline with an annual interest rate of 6.9% . At December 31, 2016 and 2015 , a subsidiary of Southern Company had capital lease obligations of approximately $29 million and $30 million , respectively, for certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.4% to 3.4% . 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, 2016 . 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. The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See " First Mortgage Bonds " herein for additional information. During 2016, in accordance with its overall growth strategy, Southern Power acquired the Mankato project. Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. See Note 12 under "Southern Power" for additional information. Bank Credit Arrangements At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year Company 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 35 500 800 1,335 1,335 — — — 35 Georgia Power — — 1,750 1,750 1,732 — — — — Gulf Power 85 195 — 280 280 45 — 25 60 Mississippi Power 173 — — 173 150 — 13 13 160 Southern Power Company (b) — — 600 600 522 — — — — Southern Company Gas (c) 75 1,925 — 2,000 1,949 — — — 75 Other 55 — — 55 55 20 — 20 35 Southern Company Consolidated $ 423 $ 3,620 $ 4,400 $ 8,443 $ 8,273 $ 65 $ 13 $ 58 $ 365 (a) Represents the Southern Company parent entity. (b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 under " Southern Power " for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million . (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1 / 4 of 1% for Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder. Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of 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, 2016 , Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants. A portion of the $8.3 billion unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2016 was approximately $1.9 billion . In addition, at December 31, 2016 , the traditional electric operating companies had approximately $0.4 billion of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2016: Commercial paper $ 1,909 1.1 % Short-term bank debt 123 1.7 % Total $ 2,032 1.1 % December 31, 2015: Commercial paper $ 740 0.7 % Short-term bank debt 500 1.4 % Total $ 1,240 0.9 % In addition to the short-term borrowings in the table above, Southern Power's subsidiary Project Credit Facilities had total amounts outstanding of $209 million and $137 million at a weighted average interest rate of 2.1% and 2.0% as of December 31, 2016 and 2015 , respectively. The amounts outstanding as of December 31, 2016 under the Project Credit Facilities were fully repaid subsequent to December 31, 2016 . Redeemable Preferred Stock of Subsidiaries Each of the traditional electric 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 "Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity. The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) Balance at December 31, 2013 $ 375 Issued — Redeemed — Balance at December 31, 2014 375 Issued — Redeemed (262 ) Other 5 Balance at December 31, 2015 118 Issued — Redeemed — Balance at December 31, 2016 $ 118
Southern Company Gas [Member]
Debt Instrument [Line Items]
CAPITALIZATION	FINANCING Southern Company Gas' 100% -owned subsidiary, Southern Company Gas Capital, was established to provide for certain of Southern Company Gas' ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital and the gas facility revenue bonds issued by Pivotal Utility Holdings. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs. Securities Due Within One Year The current portion of long-term debt at December 31, 2016 is composed of the portion of its long-term debt due within the next 12 months. At December 31, 2016 , the Company had $22 million of medium-term notes due within one year, consisting of medium-term notes of Atlanta Gas Light. At December 31, 2015 , the Company had $545 million of first mortgage bonds and senior notes due within one year. Certain of the Company's senior notes with a principal amount of $275 million were subject to change-in-control provisions that were triggered by the Merger. Under the applicable note purchase agreement, Southern Company Gas Capital was required to provide notice to the holders of these notes of the change in control and offer to prepay these notes in August 2016. None of the holders of these notes accepted the offer for prepayment. These senior notes remained on their original payment schedules and included $120 million aggregate principal amount of Series A Floating Rate notes that were repaid at maturity on October 27, 2016 and $155 million aggregate principal amount of 3.50% Senior Notes due October 27, 2018. Long-Term Debt Long-term debt of the Company at December 31, 2016 and 2015 consisted of Series A, Series B, and Series C medium-term notes of Atlanta Gas Light; senior notes of Southern Company Gas Capital; first mortgage bonds of Nicor Gas; and gas facility revenue bonds of Pivotal Utility Holdings. Southern Company Gas fully and unconditionally guarantees all of Southern Company Gas Capital's senior notes and Pivotal Utility Holdings' gas facility revenue bonds. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. The majority of the long-term debt matures after fiscal year 2021. The amount of medium-term notes outstanding at December 31, 2016 and December 31, 2015 was $159 million and $181 million , respectively. Maturities through 2021 applicable to total long-term debt are as follows: $22 million in 2017; $155 million in 2018; $350 million in 2019; $330 million in 2021; and thereafter $3.9 billion . There are no material scheduled maturities in 2020. First Mortgage Bonds The first mortgage bonds of Nicor Gas have been issued with maturities ranging from 2019 to 2038. In February and May 2016, $75 million and $50 million , respectively, of Nicor Gas' first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings. In June 2016, Nicor Gas issued $250 million aggregate principal amount of first mortgage bonds with the following terms: $100 million at 2.66% due June 20, 2026, $100 million at 2.91% due June 20, 2031, and $50 million at 3.27% due June 20, 2036. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The amount of first mortgage bonds outstanding at December 31, 2016 and December 31, 2015 was $625 million and $375 million , respectively. Gas Facility Revenue Bonds Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from each issuance then are loaned to Pivotal Utility Holdings. The amount of gas facility revenue bonds outstanding at December 31, 2016 and December 31, 2015 was $200 million . Senior Notes In May 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 3.25% Senior Notes due June 15, 2026, which are guaranteed by Southern Company Gas. The proceeds were used to repay at maturity $300 million aggregate principal amount of 6.375% Senior Notes due July 15, 2016 and for general corporate purposes. In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for a 50% equity interest in SNG, to fund the purchase of Piedmont's interest in SouthStar, to make a voluntary contribution to the pension plan, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. The amount of senior notes outstanding at December 31, 2016 and December 31, 2015 was $3.7 billion and $2.5 billion , respectively. Dividend Restrictions By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of December 31, 2016, the amount of subsidiary retained earnings restricted for dividend payment totaled $688 million . Bank Credit Arrangements Credit Facilities Bank credit arrangements under the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility provide liquidity support to Southern Company Gas Capital's and Nicor Gas' commercial paper borrowings. The Nicor Gas Credit Facility is restricted for working capital needs of Nicor Gas. In October 2015, the Company entered into agreements to amend and extend the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility. Under the terms of these agreements, the Company extended the maturity dates of the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility to November 9, 2018 and December 14, 2018, respectively. One of the banks elected not to participate in this extension and its total commitment of $75 million will continue through the fourth quarter 2017. The Company also modified the credit facilities to provide for the limited consent by the lenders to the Merger with Southern Company. Additionally, the Company made similar changes to its Bank Rate Mode Covenants Agreement relating to the Pivotal Utility Holdings gas facility revenue bonds. At December 31, 2016 , committed credit arrangements with banks were as follows: Successor Expires Expires Within One Year Company 2017 2018 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) Southern Company Gas Capital $ 49 $ 1,251 $ 1,300 $ 1,249 $ — $ 49 Nicor Gas 26 674 700 700 — 26 Total $ 75 $ 1,925 $ 2,000 $ 1,949 $ — $ 75 The Southern Company Gas Credit Facility and the Nicor Gas Credit Facility included in the table above each contain a covenant that limits the ratio of debt to capitalization (as defined in each Facility) to a maximum of 70% and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of the applicable company. At December 31, 2016 , the Company and Nicor Gas were in compliance with their respective debt limit covenants. Commercial Paper Programs The Company maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas that consist of short-term, unsecured promissory notes. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of the Company's other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. Commercial paper is included in notes payable in the consolidated balance sheets. Details of commercial paper borrowings outstanding were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) Successor – December 31, 2016: Southern Company Gas Capital $ 733 1.09 % Nicor Gas 524 0.95 % Total $ 1,257 1.03 % Predecessor – December 31, 2015: Southern Company Gas Capital $ 471 0.71 % Nicor Gas 539 0.52 % Total $ 1,010 0.60 % CAPITALIZATION The capitalization for the years ended December 31, 2016 and 2015 are as follows: Successor Predecessor Successor Predecessor 2016 2015 2016 2015 (in millions) (in millions) (percent of total) (percent of total) Long-Term Debt: Long-term notes payable — 1.47% to 9.10% due 2016-2046 (a) $ 3,887 $ 3,181 Other long-term debt — First mortgage bonds — 2.66% to 6.58% due 2016-2038 (b) 625 375 Gas facility revenue bonds — Variable rate (1.28% at 1/1/17) due 2022-2033 200 200 Total other long-term debt 825 575 Unamortized fair value adjustment of long-term debt 578 68 Unamortized debt discount (9 ) (4 ) Total long-term debt (annual interest requirement — $207 million) 5,281 3,820 Less amount due within one year 22 545 Long-term debt excluding amount due within one year 5,259 3,275 36.6 % 45.2 % Common Stockholder's Equity: Common stock — 2016: par value $0.01 per share — 2015 par value $5 per share Authorized — 2016: 100 million shares — 2015: 750 million shares Outstanding — 2016: 100 shares — 2015: 120.4 million shares Treasury — 2016: no shares — 2015: 0.2 million shares Paid-in capital 9,095 2,702 Treasury, at cost — (8 ) Retained earnings (accumulated deficit) (12 ) 1,421 Accumulated other comprehensive income (loss) 26 (186 ) Total common stockholder's equity 9,109 3,929 63.4 54.2 Noncontrolling interest — 46 — 0.6 Total stockholders' equity 9,109 3,975 Total Capitalization $ 14,368 $ 7,250 100.0 % 100.0 % (a) Long-term notes payable maturities are as follows: $22 million in 2017 ( 7.20% ); $155 million in 2018 ( 3.50% ); $300 million in 2019 ( 5.25% ); $330 million in 2021 ( 3.50% to 9.10% ); and $3.1 billion in 2022 - 2046 ( 2.45% to 8.70% ). (b) First mortgage bonds maturities are as follows: $50 million in 2019 ( 4.70% ) and $575 million in 2023 - 2038 ( 2.66% t

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information [Line Items]
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2016 and 2015 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 2016 $ 3,992 $ 940 $ 489 $ 0.53 $ 0.53 $ 0.5425 $ 51.73 $ 46.00 June 2016 4,459 1,185 623 0.67 0.66 0.5600 53.64 47.62 September 2016 6,264 1,917 1,139 1.18 1.17 0.5600 54.64 50.00 December 2016 5,181 587 197 0.20 0.20 0.5600 52.23 46.20 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 In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by $9 million in the third quarter 2016, $11 million in the second quarter 2016, and $5 million in the first quarter 2016. In addition, basic and diluted EPS increased from previously reported amounts of $1.17 and $1.16 in the third quarter 2016, respectively, $0.65 and $0.65 in the second quarter 2016, respectively, and $0.53 and $0.53 in the first quarter 2016, respectively. 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 $206 million ( $127 million after tax) in the fourth quarter 2016, $88 million ( $54 million after tax) in the third quarter 2016, $81 million ( $50 million after tax) in the second quarter 2016, $53 million ( $33 million after tax) in the first quarter 2016, $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, and $9 million ( $6 million after tax) in the first quarter 2015. 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 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2016 $ 1,331 $ 333 $ 156 June 2016 1,444 430 213 September 2016 1,785 650 351 December 2016 1,329 252 102 March 2015 $ 1,401 $ 346 $ 169 June 2015 1,455 398 200 September 2015 1,695 555 295 December 2015 1,217 264 121 In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by $2 million in the third quarter 2016, $2 million in the second quarter 2016, and $1 million in the first quarter 2016. 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 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2016 $ 1,872 $ 509 $ 269 June 2016 2,051 656 349 September 2016 2,698 1,054 599 December 2016 1,762 258 113 March 2015 $ 1,978 $ 454 $ 236 June 2015 2,016 554 277 September 2015 2,691 964 551 December 2015 1,641 376 196 In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by $1 million in the third quarter 2016, $2 million in the second quarter 2016, and $1 million in the first quarter 2016. 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 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in millions) March 2016 $ 335 $ 65 $ 29 June 2016 365 74 34 September 2016 436 90 45 December 2016 349 54 23 March 2015 $ 357 $ 72 $ 37 June 2015 384 69 35 September 2015 429 91 48 December 2015 313 58 28 In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by an immaterial amount for the first, second, and third quarters of 2016. 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 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) After Dividends on Preferred Stock (in millions) March 2016 $ 257 $ (10 ) $ 11 June 2016 277 (28 ) 2 September 2016 352 9 26 December 2016 277 (166 ) (89 ) March 2015 $ 276 $ 24 $ 35 June 2015 275 12 49 September 2015 341 (66 ) (21 ) December 2015 246 (143 ) (71 ) In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by $1 million in 2016. 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 $206 million ( $127 million after tax) in the fourth quarter 2016, $88 million ( $54 million after tax) in the third quarter 2016, $81 million ( $50 million after tax) in the second quarter 2016, $53 million ( $33 million after tax) in the first quarter 2016, $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, and $9 million ( $6 million after tax) in the first quarter 2015. 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 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income Attributable to the Company (in millions) March 2016 $ 315 $ 47 $ 50 June 2016 373 81 89 September 2016 500 134 176 December 2016 389 28 23 March 2015 $ 348 $ 67 $ 33 June 2015 337 75 46 September 2015 401 129 102 December 2015 304 55 34 The Company's business is influenced by seasonal weather conditions.
Southern Company Gas [Member]
Quarterly Financial Information [Line Items]
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for the successor period of July 1, 2016 through December 31, 2016 and for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 are as follows: Quarter Ended Operating Operating EBIT Net Income (Loss) (in millions) Predecessor - January 1, 2016 through June 30, 2016 March 2016 $ 1,334 $ 348 $ 351 $ 182 June 2016 571 (27 ) (23 ) (51 ) Successor - July 1, 2016 through December 31, 2016 September 2016 $ 543 $ 12 $ 50 $ 4 December 2016 1,109 185 221 110 Predecessor - 2015 March 2015 $ 1,721 $ 364 $ 367 $ 193 June 2015 674 107 111 42 September 2015 584 59 62 11 December 2015 962 216 221 107 The Company's business is influenced by seasonal weather conditions.

Valuation and Qualifying Accoun

Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 , AND 2014 (Stated in Thousands of Dollars) Additions Description Balance at Beginning of Period Charged to Income Charged to Other Accounts Acquisitions Deductions (Note) Balance at End of Period Provision for uncollectible accounts 2016 $ 13,341 $ 39,959 $ (1,257 ) $ 40,629 $ 49,243 $ 43,429 2015 18,253 31,074 — — 35,986 13,341 2014 17,855 43,537 — — 43,139 18,253 (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, 2016 , 2015 , AND 2014 (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 2016 $ 9,597 $ 11,310 $ — $ 10,420 $ 10,487 2015 9,143 13,500 — 13,046 9,597 2014 8,350 14,309 — 13,516 9,143 (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, 2016 , 2015 , AND 2014 (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 2016 $ 2,147 $ 14,476 $ — $ 13,787 $ 2,836 2015 6,076 16,862 — 20,791 2,147 2014 5,074 24,141 — 23,139 6,076 (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, 2016 , 2015 , AND 2014 (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 2016 $ 775 $ 2,946 $ — $ 2,989 $ 732 2015 2,087 2,041 — 3,353 775 2014 1,131 4,304 — 3,348 2,087 (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, 2016 , 2015 , AND 2014 (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 2016 $ 287 $ 1,295 $ — $ 1,088 $ 494 2015 (*) 825 (1,994 ) — (1,456 ) 287 2014 3,018 562 — 2,755 825 (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 in 2015 was of sufficient magnitude to resolve most past due amounts beyond 30 days aged receivables, accounting for the negative provision of $(2.0) million where risk of collectibility was offset by applying the refund to past due amounts. It was also of sufficient size to offset amounts previously written off in the 2012-2015 time frame, accounting for the net recoveries of $1.5 million . 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.
Southern Company Gas [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
VALUATION AND QUALIFYING ACCOUNTS	SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS FOR THE SUCCESSOR PERIOD OF JULY 1, 2016 THROUGH DECEMBER 31, 2016 AND THE PREDECESSOR PERIODS OF JANUARY 1, 2016 THROUGH JUNE 30, 2016 AND THE YEARS ENDED DECEMBER 31, 2015 AND 2014 (Stated in Thousands of Dollars) Additions Description Balance at Beginning of Period Charged to Income Charged to Other Accounts Deductions (Note) Balance at End of Period Successor – December 31, 2016 Provision for uncollectible accounts $ 37,663 $ 9,500 $ (1,257 ) $ 18,590 $ 27,316 Income tax valuation 19,182 — — — 19,182 Predecessor – June 30, 2016 Provision for uncollectible accounts $ 29,142 $ 15,976 $ 1,608 $ 9,063 $ 37,663 Income tax valuation 19,182 — — — 19,182 Predecessor – 2015 Provision for uncollectible accounts $ 35,069 $ 27,050 $ 3,017 $ 35,994 $ 29,142 Income tax valuation 19,637 — — 455 19,182 Predecessor – 2014 Provision for uncollectible accounts $ 29,261 $ 54,790 $ 1,414 $ 50,396 $ 35,069 Income tax valuation 22,329 — — 2,692 19,637 (Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies [Line Items]
General	General The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, Southern Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. Southern Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on Southern Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5, 8, and 14 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Southern Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. Southern Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of Southern Company.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans $ 3,959 $ 3,440 (a,n) Deferred income tax charges 1,590 1,514 (b) Asset retirement obligations-asset 1,080 481 (b,n) Environmental remediation-asset 491 78 (j,n) Other regulatory assets 355 299 (k) Remaining net book value of retired assets 351 283 (o) Under recovered regulatory clause revenues 273 142 (g) Loss on reacquired debt 243 248 (c) Property damage reserves-asset 206 92 (i) Kemper IGCC 201 216 (h) Vacation pay 182 178 (f,n) Long-term debt fair value adjustment 155 — (p) Deferred PPA charges 141 163 (e,n) Nuclear outage 97 88 (g) Fuel-hedging-asset 35 225 (d,n) Other cost of removal obligations (2,774 ) (1,177 ) (b) Deferred income tax credits (219 ) (187 ) (b) Over recovered regulatory clause revenues (203 ) (261 ) (g) Property damage reserves-liability (177 ) (178 ) (l) Other regulatory liabilities (110 ) (35 ) (m) Asset retirement obligations-liability (10 ) (45 ) (b,n) Total regulatory assets (liabilities), net $ 5,866 $ 5,564 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years . (d) 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 fuel and energy cost recovery mechanisms. (e) Recovered over the life of the PPA for periods up to seven years . (f) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding ten years . (h) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two , seven , or 10 years . For additional information, see Note 3 under " Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities ." (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years . (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 4 years . (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 11 years . (p) Recorded in relation to the Merger. Recovered over the remaining life of the original debt issuances, which range up to 22 years . For additional information see Note 12 under " Southern Company – Merger with Southern Company Gas ." In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under " Regulatory Matters – Alabama Power ," " Regulatory Matters – Georgia Power ," " Regulatory Matters – Gulf Power ," " Regulatory Matters – Southern Company Gas ," 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. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. 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 and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs	Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Income and Other Taxes	Income and Other Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2016 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2016 tax year along with various state NOL carryforwards, which could result in income tax benefits in the future, if utilized. See Note 5 under " Current and Deferred Income Taxes – Tax Credit Carryforwards " and " – Net Operating Loss " for additional information. Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities.
Property, Plant, and Equipment	Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Electric utilities: Generation $ 48,836 $ 41,648 Transmission 11,156 10,544 Distribution 18,418 17,670 General 4,629 4,377 Plant acquisition adjustment 126 123 Electric utility plant in service 83,165 74,362 Natural gas distribution utilities: Transportation and distribution 11,996 — Utility plant in service 95,161 74,362 Information technology equipment and software 544 222 Communications equipment 424 418 Storage facilities 1,463 — Other 824 116 Total other plant in service 3,255 756 Total plant in service $ 98,416 $ 75,118 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, 2016 2015 (in millions) Office building $ 61 $ 61 Nitrogen plant 83 83 Computer-related equipment 63 61 Gas pipeline 6 6 Less: Accumulated amortization (69 ) (59 ) Balance, net of amortization $ 144 $ 152 The amount of non-cash property additions recognized for the years ended December 31, 2016 , 2015 , and 2014 was $1.5 billion , $844 million , and $528 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, 2016 , 2015 , and 2014 was $18 million , $13 million , and $25 million , respectively.
Depreciation and Amortization	Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2016 and 2015 and 3.1% in 2014 . Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $29.3 billion and $23.7 billion at December 31, 2016 and 2015 , 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. Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million in each of 2014, 2015, and 2016 of its remaining regulatory liability related to other cost of removal obligations. See Note 3 under " Regulatory Matters – Gulf Power – Retail Base Rate Cases " for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 65 years . Accumulated depreciation for other plant in service totaled $550 million and $510 million at December 31, 2016 and 2015 , respectively.
Asset Retirement Obligations and Other Costs of Removal	Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See " Nuclear Decommissioning " herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 3,759 $ 2,201 Liabilities incurred 66 662 Liabilities settled (171 ) (37 ) Accretion 162 115 Cash flow revisions 698 818 Balance at end of year $ 4,514 $ 3,759 The increases in cash flow revisions and liabilities incurred in 2016 primarily relate to changes in ash pond closure strategy. The cash flow revisions in 2015 are primarily related 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, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, 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 with respect to compliance activities, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates.
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, 2016 and 2015 , approximately $56 million and $76 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 $58 million and $78 million at December 31, 2016 and 2015 , 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, 2016 , investment securities in the Funds totaled $1.6 billion , consisting of equity securities of $878 million , debt securities of $685 million , and $41 million of other securities. 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. 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 $1.2 billion , $1.4 billion , and $0.9 billion in 2016 , 2015 , and 2014 , respectively, all of which were reinvested. For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $114 million , which included $48 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $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 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. For Alabama Power, approximately $19 million and $20 million at December 31, 2016 and 2015, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2016 and 2015 , the accumulated provisions for the external decommissioning trust funds were as follows: External Trust Funds 2016 2015 (in millions) Plant Farley $ 790 $ 734 Plant Hatch 511 487 Plant Vogtle Units 1 and 2 303 288 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, 2016 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2: Plant Farley Plant Hatch Plant Vogtle Units 1 and 2 Decommissioning periods: Beginning year 2037 2034 2047 Completion year 2076 2075 2079 (in millions) Site study costs: Radiated structures $ 1,362 $ 678 $ 568 Spent fuel management — 160 147 Non-radiated structures 80 64 89 Total site study costs $ 1,442 $ 902 $ 804 For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in Georgia Power's 2019 base rate case. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
Allowance for Funds Used During Construction and Interest Capitalized	Allowance for Funds Used During Construction and Interest Capitalized The traditional electric operating companies and certain of the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional electric operating companies' and natural gas distribution utilities' regulated rates is capitalized in accordance with standard interest capitalization requirements.
Goodwill and Other Intangible Assets and Liabilities	Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any. The Company performed Step 1 of the impairment test in the fourth quarter 2014, which resulted in the fair values of all reporting units with goodwill exceeding their respective carrying value. However, the Company noted that the fair value of the storage and fuels reporting unit, which had $14 million of goodwill, exceeded its carrying value by less than 5% and would be at risk of failing Step 1 of the test if a further decline in fair value were to occur. While preparing the third quarter 2015 financial statements, and in connection with the 2016 annual budget process, the Company concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit's profitability required an interim goodwill impairment test to be performed as of September 30, 2015. The Company performed Step 1 and Step 2 for the interim goodwill impairment test. Based on this assessment, a non-cash impairment charge for the entire $14 million of goodwill was recorded as of September 30, 2015. For the 2016 and 2015 annual goodwill impairment tests, the Step 0 assessment was performed focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. This Step 0 analysis concluded that it is more likely than not that the fair value of the Company's reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Reserves Policy	Storm Damage Reserves Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional electric operating companies accrued $40 million in each of 2016 , 2015 , and 2014 . 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 2016 , 2015 , and 2014 , there were no such additional accruals.
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. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies	Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory	Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances of the electric utilities. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Natural Gas For Sale	Natural Gas for Sale The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis. Nicor Gas' natural gas inventory is carried at cost on a last-in, first-out (LIFO) basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income. Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.
Financial Instruments	Financial Instruments Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2016 , 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 the Company and three other traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary. The Company is subject to regulation by the FERC and the Alabama PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 12 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact.
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 $460 million , $438 million , and $400 million during 2016 , 2015 , and 2014 , 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 $249 million , $243 million , and $234 million during 2016 , 2015 , and 2014 , respectively. The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which totaled $13 million in 2016 , $11 million in 2015 , and $13 million in 2014 . Mississippi Power also reimbursed the Company for any direct fuel purchases delivered from one of the Company's transfer facilities. There were no fuel purchases in 2016. Fuel purchases were $8 million and $34 million in 2015 and 2014 , respectively. See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. Under a related tariff, the Company received $12 million in 2016, $14 million in 2015, and $12 million in 2014 and expects to recover a total of approximately $73 million from 2017 through 2023 from Gulf Power. On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016, transportation costs under this agreement were approximately $2 million . The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional electric operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans $ 947 $ 903 (i,j) Deferred income tax charges 526 522 (a,k) Under/(over) recovered regulatory clause revenues 76 (97 ) (d) Nuclear outage 70 53 (d) Remaining net book value of retired assets 69 76 (l) Vacation pay 69 66 (c,j) Loss on reacquired debt 68 75 (b) Other regulatory assets 50 53 (f) Asset retirement obligations 12 (40 ) (a) Fuel-hedging losses 1 55 (e,j) Other cost of removal obligations (684 ) (722 ) (a) Natural disaster reserve (69 ) (75 ) (h) Deferred income tax credits (65 ) (70 ) (a) Other regulatory liabilities (23 ) (8 ) (e,g) Total regulatory assets (liabilities), net $ 1,047 $ 791 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 other cost of removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years . (c) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years . See Note 3 under "Retail Regulatory Matters" for additional information. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years . Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (f) Comprised of components including generation site selection/evaluation costs, PPA capacity (to be recovered over the next 12 months ), and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. (g) Comprised of components including mine reclamation and remediation liabilities and fuel-hedging gains. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. (h) Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. (i) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Included in the deferred income tax charges are $16 million for 2016 and $17 million for 2015 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 and the Alabama PSC continuously monitor the under/over recovered balances. The Company files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP Compliance" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs	Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel.
Income and Other Taxes	Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment	Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 13,551 $ 12,820 Transmission 3,921 3,773 Distribution 6,707 6,432 General 1,840 1,713 Plant acquisition adjustment 12 12 Total plant in service $ 26,031 $ 24,750 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders.
Nuclear Outage Accounting Order	Nuclear Outage Accounting Order In accordance with an Alabama PSC order, nuclear outage operations and maintenance expenses for the two units at Plant Farley are deferred to a regulatory asset when the charges actually occur and are then amortized over a subsequent 18 -month period with the fall outage costs amortization beginning in January of the following year and the spring outage costs amortization beginning in July of the same year.
Depreciation and Amortization	Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2016 , 2.9% in 2015 , and 3.3% in 2014 . Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. In 2016, the Company submitted an updated depreciation study to the FERC and received authorization to use the recommended rates beginning January 2017. The study was also provided to the Alabama PSC. The revised rates will not have a significant impact on depreciation expense in 2017.
Asset Retirement Obligations and Other Costs of Removal	Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 1,448 $ 829 Liabilities incurred 5 402 Liabilities settled (25 ) (3 ) Accretion 73 53 Cash flow revisions 32 167 Balance at end of year $ 1,533 $ 1,448 The increase in liabilities incurred and cash flow revisions in 2016 and 2015 are primarily related to changes in ash pond closure strategy. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2016 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 with respect to compliance activities, 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.
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, 2016 , investment securities in the Funds totaled $790 million , consisting of equity securities of $552 million , debt securities of $208 million , and $30 million of other securities. 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. 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 $351 million , $438 million , and $244 million in 2016 , 2015 , and 2014 , respectively, all of which were reinvested. For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $76 million , which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million , which included $57 million related to unrealized losses on securities held in the Funds at December 31, 2015 . 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 . While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, the accumulated provisions for decommissioning were as follows: 2016 2015 (in millions) External trust funds $ 790 $ 734 Internal reserves 19 20 Total $ 809 $ 754 Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2016 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 The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies	Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory	Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments	Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . 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 electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The equity method is used for subsidiaries in which the Company has significant influence but does not control. The Company is subject to regulation by the FERC and the Georgia PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. In 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. 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 In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it is expected to have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 12 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact.
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 $606 million , $585 million , and $555 million in 2016 , 2015 , and 2014 , 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, operations, and construction management. Costs for these services amounted to $666 million , $681 million , and $643 million in 2016 , 2015 , and 2014 , respectively. The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $265 million , $179 million , and $144 million in 2016 , 2015 , and 2014 , respectively. 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 $8 million , $12 million , and $9 million in 2016 , 2015 , and 2014 , respectively. See Note 4 for additional information. In 2014, prior to Southern Company's acquisition of PowerSecure on May 9, 2016, the Company entered into agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. On October 4, 2016, the two facilities began commercial operation. Payments of approximately $118 million made by the Company to PowerSecure under the agreements since 2014 are included in utility plant in service at December 31, 2016 . On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016 , transportation costs under this agreement were approximately $35 million . Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016 , natural gas purchases made by the Company from Southern Company Gas' subsidiaries were approximately $10 million . The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . The traditional electric operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans $ 1,348 $ 1,307 (a, j) Deferred income tax charges 681 683 (b, j) Loss on reacquired debt 137 150 (c, j) Asset retirement obligations 893 411 (b, j) Vacation pay 91 91 (d, j) Cancelled construction projects 44 56 (e) Remaining net book value of retired assets 166 171 (f) Storm damage reserves 206 92 (g) Other regulatory assets 97 110 (h) Other cost of removal obligations 3 (31 ) (b) Deferred income tax credits (121 ) (105 ) (b, j) Other regulatory liabilities (39 ) (2 ) (i, j) Total regulatory assets (liabilities), net $ 3,506 $ 2,933 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 13 years . See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $26 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022. (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 36 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. The net book value of Plant Mitchell Unit 3 at December 31, 2016 was $12 million , which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $5 million , and $31 million related to obsolete inventories of certain retired units will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information. (g) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (h) Comprised of several components including deferred nuclear outages, environmental remediation, building lease, and demand-side management tariff under-recovery. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months . The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $46 million at December 31, 2016 will be determined by the Georgia PSC in the 2019 base rate case. (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.
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. The Company had $83 million in federal ITCs at December 31, 2016 that will expire by 2036. State ITCs are recognized in the period in which the credits are generated. The Company had state investment and other tax credit carryforwards totaling $345 million at December 31, 2016, which will expire between 2019 and 2027 and are expected to be fully utilized by 2023. 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: 2016 2015 (in millions) Generation $ 16,668 $ 15,386 Transmission 5,779 5,355 Distribution 9,553 9,151 General 1,813 1,921 Plant acquisition adjustment 28 28 Total plant in service $ 33,841 $ 31,841 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively.
Depreciation and Amortization	Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.8% in 2016 , 2.7% in 2015 , and 2.7% in 2014 . Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Under the terms of the 2013 ARP, the Company amortized approximately $14 million in each of 2014, 2015, and 2016 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 AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual and recovery of other retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for future obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheets as a regulatory asset. The ARO liability primarily relates to the Company's ash ponds, landfills, and gypsum cells that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 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: 2016 2015 (in millions) Balance at beginning of year $ 1,916 $ 1,255 Liabilities incurred — 6 Liabilities settled (123 ) (30 ) Accretion 77 56 Cash flow revisions 662 629 Balance at end of year $ 2,532 $ 1,916 The increase in cash flow revisions in 2016 is primarily related to changes to the Company's closure strategy for ash ponds, landfills, and gypsum cells AROs. The increase in cash flow revisions in 2015 is primarily related to changes to the Company's ash ponds, landfills, and gypsum cells ARO closure dollar and timing estimates associated with the CCR Rule and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, 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 with respect to compliance activities, 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.
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, 2016 and 2015 , approximately $56 million and $76 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 $58 million and $78 million at December 31, 2016 and 2015 , 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, 2016 , investment securities in the Funds totaled $814 million , consisting of equity securities of $326 million , debt securities of $477 million , and $11 million of other securities. 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. 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 $803 million , $980 million , and $669 million in 2016 , 2015 , and 2014 , respectively, all of which were reinvested. For 2016 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $38 million , which included $14 million related to unrealized gains on securities held in the Funds at December 31, 2016 . For 2015 , fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $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 . 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, 2016 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 $ 511 $ 303 For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4% . The Company expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in the Company's 2019 base rate case.
Allowance for Funds Used During Construction and Interest Capitalized	Allowance for Funds Used During Construction The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2016 , 2015 , and 2014 , the average AFUDC rates were 6.9% , 6.5% , and 5.6% , respectively, and AFUDC capitalized was $68 million , $56 million , and $62 million , respectively. AFUDC, net of income taxes, was 4.6% , 3.9% , and 4.6% of net income after dividends on preferred and preference stock for 2016 , 2015 , and 2014 , respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Reserves Policy	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, 2016 and December 31, 2015 , the balance in the regulatory asset related to storm damage was $206 million and $92 million , respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $176 million and $62 million included in other regulatory assets, deferred, respectively. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, costs related to storms are generally not expected to have a material impact on the Company's earnings. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information. Environmental Remediation Recovery The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In 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. 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, 2016 , the balance of the environmental remediation liability was $17 million , with approximately $2 million included in other regulatory assets, current and approximately $33 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies	Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory	Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments	Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . 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 the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), Inc. (PowerSecure), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The equity method is used for entities in which the Company has significant influence but does not control. The Company is subject to regulation by the FERC and the Florida PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 11 for disclosures impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact.
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 $80 million , $81 million , and $80 million during 2016 , 2015 , and 2014 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8 million , $12 million , and $9 million and Mississippi Power $26 million , $27 million , and $31 million in 2016 , 2015 , and 2014 , 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 made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. Payments by the Company to Alabama Power for the improvements were $12 million , $14 million , and $12 million in 2016 , 2015 , and 2014 , respectively, and are expected to be approximately $10 million annually for 2017 through 2023 , when the PPA expires. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff. In 2016, the Company purchased a turbine rotor assembly from Southern Power for $6.8 million . The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . The traditional electric operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Retiree benefit plans, net $ 160 $ 147 (a,b) PPA charges 141 163 (b,c) Closure of ash ponds 75 29 (b,d) Remaining book value of retired assets 66 4 (e) Deferred income tax charges 56 59 (f) Environmental remediation 44 46 (b,d) Regulatory asset, offset to other cost of removal 29 29 (g) Deferred return on transmission upgrades 25 10 (g) Fuel-hedging assets, net 24 104 (b,h) Other regulatory assets, net 18 16 (i) Loss on reacquired debt 18 15 (j) Asset retirement obligations, net 7 (1 ) (b,f) Other cost of removal obligations (278 ) (262 ) (f) Property damage reserve (40 ) (38 ) (e) Over recovered regulatory clause revenues (23 ) (22 ) (k) Deferred income tax credits (2 ) (3 ) (f) Total regulatory assets (liabilities), net $ 320 $ 296 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (b) Not earning a return as offset in rate base by a corresponding asset or liability. (c) Recovered over the life of the PPA for periods up to seven years . (d) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (e) Recorded and recovered or amortized as approved by the Florida PSC. (f) Asset retirement and removal assets and liabilities are recorded, 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. (g) Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. (h) 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. (i) Comprised primarily of vacation pay. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year . (j) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years . (k) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year . In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.
Revenues	Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs	Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC.
Income and Other Taxes	Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment	Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 3,001 $ 2,974 Transmission 706 691 Distribution 1,241 1,196 General 191 182 Plant acquisition adjustment 1 2 Total plant in service $ 5,140 $ 5,045 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed.
Depreciation and Amortization	Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% in both 2016 and 2015 and 3.6% in 2014 . 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 Cases" for additional information.
Asset Retirement Obligations and Other Costs of Removal	Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 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: 2016 2015 (in millions) Balance at beginning of year $ 130 $ 17 Liabilities incurred 1 105 Liabilities settled (1 ) (1 ) Accretion 4 2 Cash flow revisions 2 7 Balance at end of year $ 136 $ 130 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 and the closure of an ash pond at Plant Scholz. 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 in 2015. The cost estimates for AROs related to CCR are based on information as of December 31, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure for those facilities impacted by the CCR Rule. As further analysis is performed, 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 with respect to compliance activities, 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.
Allowance for Funds Used During Construction and Interest Capitalized	Allowance for Funds Used During Construction The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for all years presented. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 0.00% , 10.80% , and 10.93% for 2016 , 2015 , and 2014 , respectively.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Reserves Policy	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 $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2016 , 2015 , and 2014 . As of December 31, 2016 and 2015 , the balance in the Company's property damage reserve totaled approximately $40 million and $38 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 under "Retail Regulatory Matters – Retail Base Rate Cases" 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 had a balance of $1.4 million at December 31, 2016 , which is included in current liabilities in the balance sheets. The balance was zero at December 31, 2015 . There were no liabilities in excess of the reserve balance at December 31, 2016 . 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.
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	uel Inventory Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments	Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. See Note 10 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . 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 electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The Company is subject to regulation by the FERC and the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note s 5, 8, and 11 for disclosures impacted by ASU 2016-09.
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 $231 million , $295 million , and $259 million during 2016 , 2015 , and 2014 , respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $13 million , $11 million , and $13 million in 2016 , 2015 , and 2014 , respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility. There were no fuel purchases in 2016. Fuel purchases were $8 million and $34 million in 2015 and 2014 , 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 $26 million , $27 million , and $31 million in 2016 , 2015 , and 2014 , respectively. See Note 4 for additional information. On June 27, 2016, the Company received a capital contribution from Southern Company of $225 million , the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of December 31, 2016 , the amount of outstanding promissory notes to Southern Company totaled $551 million . Also, on December 14, 2016, the Company received a capital contribution from Southern Company of $400 million , the proceeds of w hich were used for general corporate purposes. See Note 6 for additional information. The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described he rein, the Company neither provided nor received any material services to or from affiliates in 2016 , 2015 , or 2014 . The traditional electric operating companies, including the Company and S outhern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2016 2015 Note (in millions) Kemper IGCC $ 201 $ 216 (h) Retiree benefit plans – regulatory assets 173 163 (a,g) Asset retirement obligations 83 70 (c) Deferred income tax charges 362 291 (c) Remaining net book value of retired assets 53 36 (b) Property tax 37 27 (d) Plant Daniel Units 3 and 4 33 29 (j) Other regulatory assets 42 27 (e,g) Fuel-hedging (realized and unrealized) losses 7 50 (f,g) Property damage (68 ) (64 ) (i) Other cost of removal obligations (170 ) (167 ) (c) Other regulatory liabilities (16 ) (11 ) (b) Total regulatory assets (liabilities), net $ 737 $ 667 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 m ay range up to 14 years . See Note 2 for additional information. (b) Other regulatory liabilities is comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year . (c) 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 49 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (d) The retail portion of property taxes is recovered through the ad valorem tax adjustment clause over a 12 -month period beginning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. (e) Other regulatory assets is comprised of numerous immaterial components including vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. (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) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two , seven , or 10 years . 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) The difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term is d eferred and amortized over a 10 -year period beginning October 2021. 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 agr eement 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 (Initial DOE Grants). Through December 31, 2016 , the Company has received grant funds of $382 million , of which $245 million of the Initial DOE Grants were used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $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 represent ed 19.8% of the Company's total operating revenues in 2016 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 above for the Company's cost-based MRA electric tariff customers, the Company has a diversified base of customers and no single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs	Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC.
Income and Other Taxes	Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. T axes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment	Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates. The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 2,632 $ 2,723 Transmission 712 688 Distribution 916 891 General 520 503 Plant acquisition adjustment 85 81 Total plant in service $ 4,865 $ 4,886 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 operations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. Through July 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 that is being recovered over 10 years beginning August 2015. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information.
Depreciation and Amortization	Depreciation, Depletion, and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 4.2% in 2016 , 4.7% in 2015 , and 3.3% in 2014 . The decrease in the 2016 depreciation rate is primarily due to fully depreciating and retiring the ARO at Plant Watson, partially offset by the increase in depreciation for the Plant Daniel scrubbers for a full year. The increase in the 2015 depreciation rate was primarily due to an 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. The Mississippi PSC approved the 2014 study, with new rates effective January 1, 2015. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities, except for the Kemper IGCC assets in service. 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 July 2015, depreciation associated with the combined cycle and the associated common facilities portion of the Kemper IGCC was deferred as a regulatory asset that is being recovered over 10 years beginning August 2015.
Asset Retirement Obligations and Other Costs of Removal	Asset Retirement Obligations and Other Costs of Removal AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in th e statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as e ither a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 177 $ 48 Liabilities incurred 15 101 Liabilities settled (23 ) (3 ) Accretion 5 4 Cash flow revisions 5 27 Balance at end of year $ 179 $ 177 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, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, 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 with respect to compliance activities, 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.
Allowance for Funds Used During Construction and Interest Capitalized	Allowance for Funds Used During Construction The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.
Reserves Policy	Provision for Property Damage The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exce ed $50,000 is charged to the reserve. Every three years the Mississippi PSC, the MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. The Company made retail accruals of $4 million for 2016 and $3 million for each of 2015 and 2014 . The Company also accrued $0.3 million annually in 2016 , 2015 , and 2014 for the wholesale jurisdiction. As of December 31, 2016 , the property damage reserve balances were $66 million and $1 million for retail and wholesa le, respectively.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies	Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as used, 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 costs are recorded 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 coal is mined, 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 related to the Kemper IGCC are recorded in CWIP. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of operations. Cash flows from d erivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives. Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company's collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 are immaterial. The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC. The Company is exposed to 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 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 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.
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 electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and 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. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. 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 In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The Company's ongoing evaluation of revenue streams and related contracts includes the evaluation of identified revenue streams tied to longer term contractual arrangements, such as certain capacity payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC Topic 840). The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. However, given the Company's core activities of selling generation capacity and energy to high credit rated customers, the Company currently does not expect the new standard to have a significant impact to net income. The Company has not elected a transition method as the ultimate impact of the new standard has not yet been determined. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged . ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. The Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of the Company.
Affiliate Transactions	Affiliate Transactions Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $258 million , $219 million , and $153 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $109 million in both 2016 and 2015 and $75 million in 2014 . 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 totaled approximately $193 million , $146 million , and $126 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Of these costs, approximately $173 million , $138 million , and $125 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively, 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 also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $11 million in each of the years ended December 31, 2016 and 2015 and $7 million for the year ended December 31, 2014 , and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. For the period subsequent to Southern Company's acquisition of Southern Company Gas, from July 1, 2016 through December 31, 2016, natural gas purchases made by the Company from Southern Company Gas' subsidiaries were approximately $17 million and are included in fuel expense on the consolidated statements of income. On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016, transportation costs under this agreement were approximately $7 million . In 2016, the Company sold a turbine rotor assembly to Gulf Power for approximately $7 million . The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
Acquisition Accounting	Acquisition Accounting The Company 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. Contingent consideration recognized at the time of each acquisition primarily relates to fixed amounts due to the seller once the facility is successfully placed in service. To the extent there is any contingent consideration with variable payments, the Company fair values the arrangement with changes recorded in net income. See Note 8 for additional information.
Revenues	Revenues The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in 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. 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: 2016 2015 2014 Georgia Power 16.5 % 15.8 % 10.1 % Duke Energy Corporation 7.8 % 8.2 % 9.1 % San Diego Gas & Electric Company 5.7 % 6.1 % 2.9 % FPL — % 10.7 % 9.7 %
Fuel Costs	Fuel Costs Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.
Income and Other Taxes	Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2016 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information.
Property, Plant, and Equipment	Property, Plant, and Equipment The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred. When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income.
Depreciation and Amortization	Depreciation The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets. The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows: Generating facility Useful life Natural gas Up to 45 years Biomass Up to 40 years Solar Up to 35 years Wind Up to 30 years The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term.
Asset Retirement Obligations and Other Costs of Removal	Asset Retirement Obligations Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 2 for acquisitions during 2015 and 2016 which contributed to the increased liability. Details of the AROs included on the consolidated balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 21 $ 13 Liabilities incurred 42 7 Accretion 1 1 Balance at end of year $ 64 $ 21
Long-Term Service Agreements	Long-Term Service Agreements The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the statements of cash flows.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the PPA. The average term of these PPAs is 19 years . The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded.
Transmission Receivables/Prepayments	Transmission Receivables/Prepayments As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five -year period and the receivable/prepayments are reduced as payments or services are received.
Cash and Cash Equivalents	Restricted Cash The use of funds received under credit facilities for Garland, Roserock, and Tranquillity is restricted for construction purposes. In addition, as a result of the Wake Wind acquisition, cash was received and is restricted for final completion payments related to construction. The aggregate amount of restricted cash at December 31, 2016 and 2015 was $13 million and $5 million , respectively, 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 Materials and supplies include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed.
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 natural gas generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company 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, electricity purchases and sales, and foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other" 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. Beginning in 2016, the Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . 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.
Southern Company Gas [Member]
Summary of Significant Accounting Policies [Line Items]
General	General On July 1, 2016, Southern Company and Southern Company Gas (formerly known as AGL Resources Inc.) (together with its subsidiaries, the Company) completed the Merger and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company and, on July 11, 2016, changed its name to Southern Company Gas. In addition to the Company, Southern Company is the parent company of four traditional electric operating companies, Southern Power, Southern Company Services, Inc. (SCS), Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc., and other direct and indirect subsidiaries. Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas across seven states through its seven natural gas distribution utilities. The Company also is involved in several other businesses that are complementary to the distribution of natural gas. The traditional electric operating companies – Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power 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. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber 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. PowerSecure, Inc. is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. The financial statements reflect the Company's investments in its subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for VIEs where the Company has an equity investment, but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation. The seven natural gas distribution utilities are subject to regulation by the regulatory agencies of each state in which they operate. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Pursuant to the Merger, Southern Company has pushed down the application of the acquisition method of accounting to the consolidated financial statements of the Company such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of the Company for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout the consolidated financial statements and notes to the financial statements, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor." Certain predecessor period data presented in the financial statements has been modified or reclassified to conform to the presentation used by the Company's new parent company, Southern Company. Changes to the consolidated statements of income include classifying operating revenues as natural gas revenues and other revenues as well as classifying cost of goods sold as cost of natural gas and cost of other sales, and presenting interest expense and AFUDC on a gross basis. Changes to the consolidated statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each category of cash flow activity. Changes to the consolidated balance sheets include changing certain captions to conform to the presentation of Southern Company.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales. The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method. 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 in 2016. 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 adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet. On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note 5 for the disclosure impacted by ASU 2016-09. On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements. On November 17, 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and will be applied retrospectively to each period presented. The Company does not intend to adopt the guidance early. The adoption of ASU 2016-18 will not have a material impact on the financial statements of the Company.
Affiliate Transactions	Affiliate Transactions Prior to the Company's completion of its acquisition of a 50% equity interest in SNG, the Company entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to the Company's investment in SNG, transportation costs paid to SNG by the Company were approximately $15 million . See Note 4 herein under "Equity Method Investments – SNG" for additional information regarding the Company's investment in SNG. The Company has an agreement with SCS under which the following services are currently being rendered to the Company as direct or allocated cost: accounting, finance and treasury, tax, information technology, auditing, insurance and pension administration, human resources, systems and procedures, purchasing, and other services. For the successor period of July 1, 2016 through December 31, 2016 , costs for these services amounted to $17 million . SouthStar and Sequent each have agreements under which they sell natural gas to SCS, as agent for the traditional electric operating companies and Southern Power. For the successor period of July 1, 2016 through December 31, 2016 , revenue from these agreements totaled $9 million and $19 million , respectively.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: Successor Predecessor 2016 2015 Note (in millions) (in millions) Deferred income tax credits $ (22 ) $ (27 ) (a) Long-term debt fair value adjustment 154 66 (b) Environmental remediation - asset 411 401 (h) Under recovered regulatory clause revenues 118 69 (c) Financial instrument hedging - asset — 30 (d,h) Other regulatory assets 58 47 (e) Other cost of removal obligations (1,616 ) (1,591 ) (a) Financial instrument hedging - liability (21 ) — (d,h) Other regulatory liabilities (18 ) (20 ) (f) Retiree benefit plans 325 125 (g,h) Over recovered regulatory clause revenues (104 ) (87 ) (c) Total regulatory assets (liabilities), net $ (715 ) $ (987 ) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Deferred income tax assets and liabilities are amortized over the related property lives, which range up to 30 years . (b) Recovered over the remaining life of the original debt issuances, which range up to 22 years . (c) Recorded and recovered or amortized as approved or accepted by the applicable state regulatory agencies over periods not exceeding nine years . (d) Financial instrument-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years . Upon final settlement, actual costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause. (e) Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, and deferred depreciation expense, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding ten years . (f) Comprised of several components including energy efficiency programs and unamortized bond issuance costs which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding four years . (g) Recovered and amortized over the average remaining service period which range up to 11 years . See Note 2 for additional information. (h) Not earning a return as offset in rate base by a corresponding asset or liability. In the event that a portion of its operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the 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 "Regulatory Matters" for additional information.
Revenues	Revenues Gas Distribution Operations The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the Company's utilities. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. All of the natural gas utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period. The tariffs for Virginia Natural Gas, Elizabethtown Gas, and Chattanooga Gas contain weather normalization adjustments (WNAs) that partially mitigate the impact of unusually cold or warm weather on customer billings and natural gas revenues. The WNAs have the effect of reducing customer bills when winter weather is colder than normal and increasing customer bills when weather is warmer than normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas, and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage. The WNAs and revenue normalization mechanisms are alternative revenue programs, which allow recognition of revenue prior to billing as long as the amounts will be collected within 24 months of recognition. Revenue Taxes The Company charges customers for gas revenue and gas use taxes imposed on the Company and remits amounts owed to various governmental authorities. Gas revenue taxes are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on the Company are recorded as operating expenses on the statements of income. Gas use taxes are excluded from revenue and expense with the related administrative fee included in operating revenues when the tax is imposed on the customer. Revenue taxes included in operating expenses were $31 million for the successor period of July 1, 2016 through December 31, 2016 and $56 million , $101 million , and $130 million for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , respectively. Gas Marketing Services The Company recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. The Company also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period. The Company recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. Revenues for warranty and repair contracts are recognized on a straight-line basis over the contract term while revenues for maintenance services are recognized at the time such services are performed. Wholesale Gas Services The Company nets revenues from energy and risk management activities with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. The Company records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue. Concentration of Revenue The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues
Cost Of Natural Gas	Cost of Natural Gas and Other Sales Gas Distribution Operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the Company charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the consolidated balance sheets as regulatory assets and regulatory liabilities, respectively. Gas Marketing Services The Company's gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, the Company also includes costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives. The Company records the costs to service its warranty and repair contract claims as cost of other sales.
Income and Other Taxes	Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheet, excluding revenue taxes which are presented on the statements of income. See "Revenues – Gas Distribution Operations – Revenue Taxes" herein for additional information. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities.
Property, Plant, and Equipment	Property, Plant, and Equipment Property, plant, and equipment is stated at original cost, or fair value at the effective date of the Merger as appropriate, less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: Successor Predecessor 2016 2015 (in millions) (in millions) Utility plant in service $ 11,996 $ 9,912 Information technology equipment and software 324 415 Storage facilities 1,463 1,255 Other 725 570 Total other plant in service 2,512 2,240 Total plant in service $ 14,508 $ 12,152 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. The portion of pad gas at the Company's natural gas storage facilities considered to be non-recoverable is recorded as depreciable property, plant, and equipment, while the recoverable or retained portion is recorded as non-depreciable property, plant, and equipment. The amount of non-cash property additions recognized for the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 was $63 million , $41 million , $48 million , and $31 million , respectively. These amounts are comprised of construction-related accounts payable outstanding at the end of each period.
Depreciation and Amortization	Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.8% in 2016 and 2.7% in each of 2015 and 2014. Depreciation studies are conducted periodically to update the composite rates that are approved by the respective state regulatory agency. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the asset are retired when the related property unit is retired. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over the following useful lives: five to 15 years for transportation equipment, 40 to 60 years for storage facilities, and up to 65 years for other assets.
Allowance for Funds Used During Construction and Interest Capitalized	Allowance for Funds Used During Construction The Company records AFUDC for Atlanta Gas Light, Nicor Gas, Chattanooga Gas, and Elizabethtown Gas, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The capital expenditures of the other three natural gas utilities do not qualify for AFUDC treatment. The Company's AFUDC composite rates are as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years ended December 31, 2016 2016 2015 2014 Atlanta Gas Light 4.05 % 4.05 % 8.10 % 8.10 % Chattanooga Gas (*) 3.71 3.71 7.41 7.41 Elizabethtown Gas (*) 0.84 0.84 1.69 0.44 Nicor Gas (*) 1.50 1.50 0.82 0.24 (*) Variable rate is determined by the FERC method of AFUDC accounting. Cash payments for interest during the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 totaled $135 million , $119 million , $181 million , and $187 million , respectively.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Energy Marketing Receivables and Payables	Energy Marketing Receivables and Payables Wholesale gas services provides services to retail gas marketers, wholesale gas marketers, utility companies, and industrial customers. These counterparties utilize netting agreements that enable wholesale gas services to net receivables and payables by counterparty upon settlement. Wholesale gas services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale gas services' counterparties are settled net, they are recorded on a gross basis in the consolidated balance sheets as energy marketing receivables and energy marketing payables. Wholesale gas services has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if the Company's credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale gas services would need to post collateral to continue transacting business with some of its counterparties. As of December 31, 2016 and 2015 , the required collateral in the event of a credit rating downgrade was immaterial. Wholesale gas services has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. Counterparty credit risk is evaluated using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody's rating to an internal rating ranging from 9 to 1 , with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being equivalent to D/Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2016 , the top 20 counterparties represented 46% , or $205 million , of the total counterparty exposure and had a weighted average S&P equivalent rating of A-. Credit policies were established to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale gas services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of the Company's credit risk. Wholesale gas services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.
Receivables and Allowance for Uncollectible Accounts	Receivables and Allowance for Uncollectible Accounts The Company's other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, an allowance for doubtful accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer's inability to pay, an allowance for doubtful accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible. Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 14 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. Atlanta Gas Light obtains credit security support in an amount equal to no less than two times a Marketer's highest month's estimated bill from Atlanta Gas Light.
Materials and Supplies	Materials and Supplies Generally, materials and supplies include propane gas inventory, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Natural Gas For Sale	Natural Gas for Sale The natural gas distribution utilities, with the exception of Nicor Gas, record natural gas inventories on a WACOG basis. In Georgia's competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. Nicor Gas' inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on the Company's net income. At December 31, 2016 , the Nicor Gas LIFO inventory balance was $148 million . Based on the average cost of gas purchased in December 2016, the estimated replacement cost of Nicor Gas' inventory at December 31, 2016 was $310 million , which exceeded the LIFO cost by $162 million . During 2016 , Nicor Gas did not liquidate any LIFO-based inventory. The gas marketing services, wholesale gas services, and all other segments record inventory at LOCOM, with cost determined on a WACOG basis. For these segments, the Company evaluates the weighted average cost of its natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. As indicated in the following table, for any declines considered to be other than temporary, the Company recorded LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. Successor Predecessor July 1, 2016 to December 31, 2016 January 1, 2016 to June 30, 2016 2015 2014 (in millions) (in millions) Gas marketing services $ — $ — $ 3 $ 4 Wholesale gas services 1 3 19 73 All other — — 1 — Total $ 1 $ 3 $ 23 $ 77
Fair Value Measurements	Fair Value Measurements The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. The nonfinancial assets and liabilities include pension and welfare benefits. See Notes 2 and 9 for additional fair value disclosures. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows: Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company's Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets. Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include shorter tenor exchange-traded and non-exchange-traded derivatives such as over-the-counter (OTC) forwards and options and certain retirement plan assets. Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management's best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company's pension and welfare benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred.
Financial Instruments	Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, weather, interest rates, and commodity prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives. The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016 . The Company enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the consolidated statements of income. Wholesale gas services purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price that can be received in the future, resulting in positive net natural gas revenues. NYMEX futures and OTC contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. The Company enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the consolidated balance sheets, with changes in fair value recorded in natural gas revenues on the consolidated statements of income in the period of change. These contracts are not designated as hedges for accounting purposes. The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the consolidated statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income	Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.
Variable Interest Entities	Non-Wholly Owned Entities The Company holds ownership interests in a number of business ventures with varying ownership structures and evaluates all of its partnership interests and other variable interests to determine if each entity is a VIE. If a venture is a VIE for which the Company is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. The Company reassesses its conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. See Note 4 under "Variable Interest Entities" for additional information. For entities that are not determined to be VIEs, the Company evaluates whether it has control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of the Company are consolidated, and entities over which the Company can exert significant influence, but does not control, are accounted for under the equity method of accounting. However, the Company also invests in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless the interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures. Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries within the other property and investments section in the consolidated balance sheets and the equity income is recorded within earnings from equity method investments within the other income (expense) section in the consolidated statements of income.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 Note (in millions) Retiree benefit plans $ 3,959 $ 3,440 (a,n) Deferred income tax charges 1,590 1,514 (b) Asset retirement obligations-asset 1,080 481 (b,n) Environmental remediation-asset 491 78 (j,n) Other regulatory assets 355 299 (k) Remaining net book value of retired assets 351 283 (o) Under recovered regulatory clause revenues 273 142 (g) Loss on reacquired debt 243 248 (c) Property damage reserves-asset 206 92 (i) Kemper IGCC 201 216 (h) Vacation pay 182 178 (f,n) Long-term debt fair value adjustment 155 — (p) Deferred PPA charges 141 163 (e,n) Nuclear outage 97 88 (g) Fuel-hedging-asset 35 225 (d,n) Other cost of removal obligations (2,774 ) (1,177 ) (b) Deferred income tax credits (219 ) (187 ) (b) Over recovered regulatory clause revenues (203 ) (261 ) (g) Property damage reserves-liability (177 ) (178 ) (l) Other regulatory liabilities (110 ) (35 ) (m) Asset retirement obligations-liability (10 ) (45 ) (b,n) Total regulatory assets (liabilities), net $ 5,866 $ 5,564 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. (c) Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years . (d) 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 fuel and energy cost recovery mechanisms. (e) Recovered over the life of the PPA for periods up to seven years . (f) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding ten years . (h) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two , seven , or 10 years . For additional information, see Note 3 under " Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities ." (i) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (j) Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. (k) Comprised of numerous immaterial components including deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years . (l) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. (m) Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 4 years . (n) Not earning a return as offset in rate base by a corresponding asset or liability. (o) Amortized as approved by the appropriate state PSCs over periods generally up to 11 years . (p) Recorded in relation to the Merger. Recovered over the remaining life of the original debt issuances, which range up to 22 years . For additional information see Note 12 under " Southern Company – Merger with Southern Company Gas ."
Property Plant and Equipment	The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Electric utilities: Generation $ 48,836 $ 41,648 Transmission 11,156 10,544 Distribution 18,418 17,670 General 4,629 4,377 Plant acquisition adjustment 126 123 Electric utility plant in service 83,165 74,362 Natural gas distribution utilities: Transportation and distribution 11,996 — Utility plant in service 95,161 74,362 Information technology equipment and software 544 222 Communications equipment 424 418 Storage facilities 1,463 — Other 824 116 Total other plant in service 3,255 756 Total plant in service $ 98,416 $ 75,118
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, 2016 2015 (in millions) Office building $ 61 $ 61 Nitrogen plant 83 83 Computer-related equipment 63 61 Gas pipeline 6 6 Less: Accumulated amortization (69 ) (59 ) Balance, net of amortization $ 144 $ 152
Asset Retirement Obligations and Other Costs of Removal	Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 3,759 $ 2,201 Liabilities incurred 66 662 Liabilities settled (171 ) (37 ) Accretion 162 115 Cash flow revisions 698 818 Balance at end of year $ 4,514 $ 3,759
Accumulated Provisions for Decommissioning	At December 31, 2016 and 2015 , the accumulated provisions for the external decommissioning trust funds were as follows: External Trust Funds 2016 2015 (in millions) Plant Farley $ 790 $ 734 Plant Hatch 511 487 Plant Vogtle Units 1 and 2 303 288
Estimated Cost of Decommissioning	The estimated costs of decommissioning as of December 31, 2016 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2: Plant Farley Plant Hatch Plant Vogtle Units 1 and 2 Decommissioning periods: Beginning year 2037 2034 2047 Completion year 2076 2075 2079 (in millions) Site study costs: Radiated structures $ 1,362 $ 678 $ 568 Spent fuel management — 160 147 Non-radiated structures 80 64 89 Total site study costs $ 1,442 $ 902 $ 804
Schedule of Finite-Lived and Infinite-Lived Intangible Assets	At December 31, 2016 , other intangible assets were as follows: Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other (in millions) Other intangible assets subject to amortization: Customer relationships 11-26 years $ 268 $ (32 ) $ 236 Trade names 5-28 years 158 (5 ) 153 Patents 3-10 years 4 — 4 Backlog 5 years 5 (1 ) 4 Storage and transportation contracts 1-5 years 64 (2 ) 62 Software and other 1-12 years 2 — 2 PPA fair value adjustments 19-20 years 456 (22 ) 434 Total other intangible assets subject to amortization $ 957 $ (62 ) $ 895 Other intangible assets not subject to amortization: Federal Communications Commission licenses 75 — 75 Total other intangible assets $ 1,032 $ (62 ) $ 970
Future Amortization Expense for Intangible Assets	As of December 31, 2016 , the estimated amortization associated with other intangible assets is as follows: Amortization (in millions) 2017 $ 108 2018 93 2019 74 2020 63 2021 56
Future Amortization Expense for Intangible Liabilities	The estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: Amortization (in millions) 2017 $ 29 2018 24 2019 17
Net Investments in Leveraged Leases	Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31: 2016 2015 (in millions) Net rentals receivable $ 1,481 $ 1,487 Unearned income (707 ) (732 ) Investment in leveraged leases 774 755 Deferred taxes from leveraged leases (309 ) (303 ) Net investment in leveraged leases $ 465 $ 452
Components of Income from Leveraged Leases	A summary of the components of income from the leveraged leases follows: 2016 2015 2014 (in millions) Pretax leveraged lease income $ 25 $ 20 $ 24 Income tax expense (9 ) (7 ) (9 ) Net leveraged lease income $ 16 $ 13 $ 15
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, 2015 $ (48 ) $ — $ (82 ) $ (130 ) Current period change (67 ) — 17 (50 ) Balance at December 31, 2016 $ (115 ) $ — $ (65 ) $ (180 )
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: 2016 2015 Note (in millions) Retiree benefit plans $ 947 $ 903 (i,j) Deferred income tax charges 526 522 (a,k) Under/(over) recovered regulatory clause revenues 76 (97 ) (d) Nuclear outage 70 53 (d) Remaining net book value of retired assets 69 76 (l) Vacation pay 69 66 (c,j) Loss on reacquired debt 68 75 (b) Other regulatory assets 50 53 (f) Asset retirement obligations 12 (40 ) (a) Fuel-hedging losses 1 55 (e,j) Other cost of removal obligations (684 ) (722 ) (a) Natural disaster reserve (69 ) (75 ) (h) Deferred income tax credits (65 ) (70 ) (a) Other regulatory liabilities (23 ) (8 ) (e,g) Total regulatory assets (liabilities), net $ 1,047 $ 791 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 other cost of removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years . (c) Recorded as earned by employees and recovered as paid, generally within one year . This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years . See Note 3 under "Retail Regulatory Matters" for additional information. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years . Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (f) Comprised of components including generation site selection/evaluation costs, PPA capacity (to be recovered over the next 12 months ), and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. (g) Comprised of components including mine reclamation and remediation liabilities and fuel-hedging gains. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. (h) Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. (i) Recovered and amortized over the average remaining service period which may range up to 15 years . See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Included in the deferred income tax charges are $16 million for 2016 and $17 million for 2015 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: 2016 2015 (in millions) Generation $ 13,551 $ 12,820 Transmission 3,921 3,773 Distribution 6,707 6,432 General 1,840 1,713 Plant acquisition adjustment 12 12 Total plant in service $ 26,031 $ 24,750
Asset Retirement Obligations and Other Costs of Removal	Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 1,448 $ 829 Liabilities incurred 5 402 Liabilities settled (25 ) (3 ) Accretion 73 53 Cash flow revisions 32 167 Balance at end of year $ 1,533 $ 1,448
Accumulated Provisions for Decommissioning	At December 31, the accumulated provisions for decommissioning were as follows: 2016 2015 (in millions) External trust funds $ 790 $ 734 Internal reserves 19 20 Total $ 809 $ 754
Estimated Cost of Decommissioning	The estimated costs of decommissioning as of December 31, 2016 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
Southern Company Gas [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: Successor Predecessor 2016 2015 Note (in millions) (in millions) Deferred income tax credits $ (22 ) $ (27 ) (a) Long-term debt fair value adjustment 154 66 (b) Environmental remediation - asset 411 401 (h) Under recovered regulatory clause revenues 118 69 (c) Financial instrument hedging - asset — 30 (d,h) Other regulatory assets 58 47 (e) Other cost of removal obligations (1,616 ) (1,591 ) (a) Financial instrument hedging - liability (21 ) — (d,h) Other regulatory liabilities (18 ) (20 ) (f) Retiree benefit plans 325 125 (g,h) Over recovered regulatory clause revenues (104 ) (87 ) (c) Total regulatory assets (liabilities), net $ (715 ) $ (987 ) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Deferred income tax assets and liabilities are amortized over the related property lives, which range up to 30 years . (b) Recovered over the remaining life of the original debt issuances, which range up to 22 years . (c) Recorded and recovered or amortized as approved or accepted by the applicable state regulatory agencies over periods not exceeding nine years . (d) Financial instrument-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years . Upon final settlement, actual costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause. (e) Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, and deferred depreciation expense, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding ten years . (f) Comprised of several components including energy efficiency programs and unamortized bond issuance costs which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding four years . (g) Recovered and amortized over the average remaining service period which range up to 11 years . See Note 2 for additional information. (h) Not earning a return as 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: Successor Predecessor 2016 2015 (in millions) (in millions) Utility plant in service $ 11,996 $ 9,912 Information technology equipment and software 324 415 Storage facilities 1,463 1,255 Other 725 570 Total other plant in service 2,512 2,240 Total plant in service $ 14,508 $ 12,152
Schedule of Finite-Lived and Infinite-Lived Intangible Assets	Goodwill and other intangible assets consisted of the following: Successor - At December 31, 2016 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Intangible Assets, Net (in millions) Other intangible assets subject to amortization: Gas marketing services Customer relationships 11-14 years $ 221 $ (30 ) $ 191 Trade names 10-28 years 115 (2 ) 113 Wholesale gas services Storage and transportation contracts 1-5 years 64 (2 ) 62 Total intangible assets subject to amortization $ 400 $ (34 ) $ 366 Goodwill: Gas distribution operations (*) $ 4,702 $ — 4,702 Gas marketing services 1,265 — 1,265 Total goodwill $ 5,967 $ — $ 5,967 (*) Measurement period adjustments were recorded in acquisition accounting during the fourth quarter 2016 that resulted in a net $30 million increase to goodwill. Predecessor - At December 31, 2015 Estimated Useful Life Gross Carrying Amount Accumulated Amortization Other Intangible Assets, Net (in millions) Other intangible assets subject to amortization: Gas marketing services Customer relationships 11-14 years $ 132 $ (57 ) $ 75 Trade names 10-28 years 45 (11 ) 34 Total intangible assets subject to amortization $ 177 $ (68 ) $ 109 Goodwill: Gas distribution operations $ 1,640 $ — $ 1,640 Gas marketing services 173 — 173 Total goodwill $ 1,813 $ — $ 1,813
Future Amortization Expense for Intangible Assets	As of December 31, 2016 , the estimated amortization associated with other intangible assets is as follows: Amortization (in millions) 2017 $ 73 2018 58 2019 40 2020 28 2021 21
Future Amortization Expense for Intangible Liabilities	The estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: Amortization (in millions) 2017 $ 29 2018 24 2019 17
Schedule of Inventory, Lower of Cost or Market Adjustment	As indicated in the following table, for any declines considered to be other than temporary, the Company recorded LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. Successor Predecessor July 1, 2016 to December 31, 2016 January 1, 2016 to June 30, 2016 2015 2014 (in millions) (in millions) Gas marketing services $ — $ — $ 3 $ 4 Wholesale gas services 1 3 19 73 All other — — 1 — Total $ 1 $ 3 $ 23 $ 77
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: 2016 2015 Note (in millions) Retiree benefit plans, net $ 160 $ 147 (a,b) PPA charges 141 163 (b,c) Closure of ash ponds 75 29 (b,d) Remaining book value of retired assets 66 4 (e) Deferred income tax charges 56 59 (f) Environmental remediation 44 46 (b,d) Regulatory asset, offset to other cost of removal 29 29 (g) Deferred return on transmission upgrades 25 10 (g) Fuel-hedging assets, net 24 104 (b,h) Other regulatory assets, net 18 16 (i) Loss on reacquired debt 18 15 (j) Asset retirement obligations, net 7 (1 ) (b,f) Other cost of removal obligations (278 ) (262 ) (f) Property damage reserve (40 ) (38 ) (e) Over recovered regulatory clause revenues (23 ) (22 ) (k) Deferred income tax credits (2 ) (3 ) (f) Total regulatory assets (liabilities), net $ 320 $ 296 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 14 years . See Note 2 for additional information. (b) Not earning a return as offset in rate base by a corresponding asset or liability. (c) Recovered over the life of the PPA for periods up to seven years . (d) Recovered through the environmental cost recovery clause when the remediation or the work is performed. (e) Recorded and recovered or amortized as approved by the Florida PSC. (f) Asset retirement and removal assets and liabilities are recorded, 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. (g) Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. (h) 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. (i) Comprised primarily of vacation pay. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year . (j) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years . (k) Recorded and recovered or amortized as approved by the Florida PSC, generally within one year .
Property Plant and Equipment	The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 3,001 $ 2,974 Transmission 706 691 Distribution 1,241 1,196 General 191 182 Plant acquisition adjustment 1 2 Total plant in service $ 5,140 $ 5,045
Asset Retirement Obligations and Other Costs of Removal	Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 130 $ 17 Liabilities incurred 1 105 Liabilities settled (1 ) (1 ) Accretion 4 2 Cash flow revisions 2 7 Balance at end of year $ 136 $ 130
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: 2016 2015 Note (in millions) Retiree benefit plans $ 1,348 $ 1,307 (a, j) Deferred income tax charges 681 683 (b, j) Loss on reacquired debt 137 150 (c, j) Asset retirement obligations 893 411 (b, j) Vacation pay 91 91 (d, j) Cancelled construction projects 44 56 (e) Remaining net book value of retired assets 166 171 (f) Storm damage reserves 206 92 (g) Other regulatory assets 97 110 (h) Other cost of removal obligations 3 (31 ) (b) Deferred income tax credits (121 ) (105 ) (b, j) Other regulatory liabilities (39 ) (2 ) (i, j) Total regulatory assets (liabilities), net $ 3,506 $ 2,933 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Recovered and amortized over the average remaining service period which may range up to 13 years . See Note 2 for additional information. (b) Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years . Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $26 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022. (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 36 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. The net book value of Plant Mitchell Unit 3 at December 31, 2016 was $12 million , which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $5 million , and $31 million related to obsolete inventories of certain retired units will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information. (g) Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information. (h) Comprised of several components including deferred nuclear outages, environmental remediation, building lease, and demand-side management tariff under-recovery. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months . The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $46 million at December 31, 2016 will be determined by the Georgia PSC in the 2019 base rate case. (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: 2016 2015 (in millions) Generation $ 16,668 $ 15,386 Transmission 5,779 5,355 Distribution 9,553 9,151 General 1,813 1,921 Plant acquisition adjustment 28 28 Total plant in service $ 33,841 $ 31,841
Asset Retirement Obligations and Other Costs of Removal	Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 1,916 $ 1,255 Liabilities incurred — 6 Liabilities settled (123 ) (30 ) Accretion 77 56 Cash flow revisions 662 629 Balance at end of year $ 2,532 $ 1,916
Accumulated Provisions for Decommissioning	The site study costs and external trust funds for decommissioning as of December 31, 2016 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 $ 511 $ 303
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: 2016 2015 Note (in millions) Kemper IGCC $ 201 $ 216 (h) Retiree benefit plans – regulatory assets 173 163 (a,g) Asset retirement obligations 83 70 (c) Deferred income tax charges 362 291 (c) Remaining net book value of retired assets 53 36 (b) Property tax 37 27 (d) Plant Daniel Units 3 and 4 33 29 (j) Other regulatory assets 42 27 (e,g) Fuel-hedging (realized and unrealized) losses 7 50 (f,g) Property damage (68 ) (64 ) (i) Other cost of removal obligations (170 ) (167 ) (c) Other regulatory liabilities (16 ) (11 ) (b) Total regulatory assets (liabilities), net $ 737 $ 667 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 m ay range up to 14 years . See Note 2 for additional information. (b) Other regulatory liabilities is comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year . (c) 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 49 years . Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (d) The retail portion of property taxes is recovered through the ad valorem tax adjustment clause over a 12 -month period beginning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. (e) Other regulatory assets is comprised of numerous immaterial components including vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. (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) Includes $97 million of regulatory assets currently in rates to be recovered over periods of two , seven , or 10 years . 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) The difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term is d eferred and amortized over a 10 -year period beginning October 2021.
Property Plant and Equipment	The Company's property, plant, and equipment in service consisted of the following at December 31: 2016 2015 (in millions) Generation $ 2,632 $ 2,723 Transmission 712 688 Distribution 916 891 General 520 503 Plant acquisition adjustment 85 81 Total plant in service $ 4,865 $ 4,886
Asset Retirement Obligations and Other Costs of Removal	Details of the AROs included in the balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 177 $ 48 Liabilities incurred 15 101 Liabilities settled (23 ) (3 ) Accretion 5 4 Cash flow revisions 5 27 Balance at end of year $ 179 $ 177
Southern Power [Member]
Summary of Significant Accounting Policies [Line Items]
Property Plant and Equipment	The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows: Generating facility Useful life Natural gas Up to 45 years Biomass Up to 40 years Solar Up to 35 years Wind Up to 30 years
Asset Retirement Obligations and Other Costs of Removal	Details of the AROs included on the consolidated balance sheets are as follows: 2016 2015 (in millions) Balance at beginning of year $ 21 $ 13 Liabilities incurred 42 7 Accretion 1 1 Balance at end of year $ 64 $ 21
Future Amortization Expense for Intangible Assets	The amortization expense for each of the next five years is as follows: Amortization Expense (in millions) 2017 $ 25 2018 25 2019 25 2020 25 2021 25
Schedule of Revenue by Major Customers by Reporting Segments	The following table shows the percentage of total revenues for the top three customers: 2016 2015 2014 Georgia Power 16.5 % 15.8 % 10.1 % Duke Energy Corporation 7.8 % 8.2 % 9.1 % San Diego Gas & Electric Company 5.7 % 6.1 % 2.9 % FPL — % 10.7 % 9.7 %
Composite AFUDC Rates [Member] | Southern Company Gas [Member]
Summary of Significant Accounting Policies [Line Items]
Property Plant and Equipment	The Company's AFUDC composite rates are as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years ended December 31, 2016 2016 2015 2014 Atlanta Gas Light 4.05 % 4.05 % 8.10 % 8.10 % Chattanooga Gas (*) 3.71 3.71 7.41 7.41 Elizabethtown Gas (*) 0.84 0.84 1.69 0.44 Nicor Gas (*) 1.50 1.50 0.82 0.24 (*) Variable rate is determined by the FERC method of AFUDC accounting.

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.58 % 4.17 % 5.02 % Discount rate – interest costs 3.88 4.17 5.02 Discount rate – service costs 4.98 4.48 5.02 Expected long-term return on plan assets 8.16 8.20 8.20 Annual salary increase 4.37 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.38 % 4.04 % 4.85 % Discount rate – interest costs 3.66 4.04 4.85 Discount rate – service costs 4.85 4.39 4.85 Expected long-term return on plan assets 6.66 6.97 7.15 Annual salary increase 4.37 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.40 % 4.67 % Annual salary increase 4.37 4.46 Other postretirement benefit plans Discount rate 4.23 % 4.51 % Annual salary increase 4.37 4.46
Schedule of Health Care Cost Trend Rates	The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent 1 Percent (in millions) Benefit obligation $ 128 $ 110 Service and interest costs 4 3
Changes in projected benefit obligations and fair value of plan assets	Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 10,542 $ 10,909 Acquisitions 1,244 — Service cost 262 257 Interest cost 422 445 Benefits paid (466 ) (487 ) Actuarial (gain) loss 381 (582 ) Balance at end of year 12,385 10,542 Change in plan assets Fair value of plan assets at beginning of year 9,234 9,690 Acquisitions 837 — Actual return (loss) on plan assets 902 (14 ) Employer contributions 1,076 45 Benefits paid (466 ) (487 ) Fair value of plan assets at end of year 11,583 9,234 Accrued liability $ (802 ) $ (1,308 )
Schedule of amounts recognized in other comprehensive income (loss)	The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: Accumulated OCI Net Regulatory Assets (Liabilities) (in millions) Balance at December 31, 2014 $ 8 $ 366 Net (gain) loss — 33 Change in prior service costs — 33 Reclassification adjustments: Amortization of prior service costs — (4 ) Amortization of net gain (loss) — (17 ) Total reclassification adjustments — (21 ) Total change — 45 Balance at December 31, 2015 $ 8 $ 411 Net (gain) loss (1 ) (13 ) Reclassification adjustments: Amortization of prior service costs — (6 ) Amortization of net gain (loss) — (14 ) Total reclassification adjustments — (20 ) Total change (1 ) (33 ) Balance at December 31, 2016 $ 7 $ 378
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, 2016 and 2015 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 2017 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2016: Accumulated OCI $ 4 $ 96 Regulatory assets 51 3,069 Total $ 55 $ 3,165 Balance at December 31, 2015: Accumulated OCI $ 3 $ 122 Regulatory assets 27 2,971 Total $ 30 $ 3,093 Estimated amortization in net periodic pension cost in 2017: Accumulated OCI $ 1 $ 7 Regulatory assets 11 155 Total $ 12 $ 162
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, 2016 and 2015 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2014 $ 134 $ 3,073 Net (gain) loss 1 155 Reclassification adjustments: Amortization of prior service costs (1 ) (24 ) Amortization of net gain (loss) (9 ) (206 ) Total reclassification adjustments (10 ) (230 ) Total change (9 ) (75 ) Balance at December 31, 2015 $ 125 $ 2,998 Net (gain) loss (20 ) 243 Change in prior service costs 2 37 Reclassification adjustments: Amortization of prior service costs (1 ) (13 ) Amortization of net gain (loss) (6 ) (145 ) Total reclassification adjustments (7 ) (158 ) Total change (25 ) 122 Balance at December 31, 2016 $ 100 $ 3,120
Estimated pension benefit payments	At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 571 2018 593 2019 620 2020 646 2021 666 2022 to 2026 3,673
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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 1,989 $ 1,986 Acquisitions 338 — Service cost 22 23 Interest cost 76 78 Benefits paid (119 ) (102 ) Actuarial (gain) loss (16 ) (38 ) Plan amendments — 34 Retiree drug subsidy 7 8 Balance at end of year 2,297 1,989 Change in plan assets Fair value of plan assets at beginning of year 833 900 Acquisitions 100 — Actual return (loss) on plan assets 58 (12 ) Employer contributions 65 39 Benefits paid (112 ) (94 ) Fair value of plan assets at end of year 944 833 Accrued liability $ (1,353 ) $ (1,156 )
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, 2016 and 2015 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 2017 . Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2016: Accumulated OCI $ — $ 7 Net regulatory assets 25 353 Total $ 25 $ 360 Balance at December 31, 2015: Accumulated OCI $ — $ 8 Net regulatory assets 32 379 Total $ 32 $ 387 Estimated amortization as net periodic postretirement benefit cost in 2017: Net regulatory assets $ 6 $ 13
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) 2017 $ 145 $ (10 ) $ 135 2018 150 (11 ) 139 2019 155 (12 ) 143 2020 159 (13 ) 146 2021 162 (14 ) 148 2022 to 2026 823 (73 ) 750
Pension plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 3,207 $ 2,998 Other current liabilities (53 ) (46 ) Employee benefit obligations (749 ) (1,262 ) Other regulatory liabilities, deferred (87 ) — Accumulated OCI 100 125
Components of net periodic benefit cost	Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 262 $ 257 $ 213 Interest cost 422 445 435 Expected return on plan assets (782 ) (724 ) (645 ) Recognized net (gain) loss 150 215 110 Net amortization 14 25 26 Net periodic pension cost $ 66 $ 218 $ 139
Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 419 $ 433 Other current liabilities (4 ) (4 ) Employee benefit obligations (1,349 ) (1,152 ) Other regulatory liabilities, deferred (41 ) (22 ) Accumulated OCI 7 8
Components of net periodic benefit cost	Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 22 $ 23 $ 21 Interest cost 76 78 79 Expected return on plan assets (60 ) (58 ) (59 ) Net amortization 21 21 6 Net periodic postretirement benefit cost $ 59 $ 64 $ 47
Fair values of benefit plan assets	The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Total Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 118 $ 28 $ — $ — $ 146 39 % 40 % International equity (*) 37 61 — — 98 23 21 Fixed income: 29 31 U.S. Treasury, government, and agency bonds — 24 — — 24 Corporate bonds — 30 — — 30 Pooled funds — 49 — — 49 Cash equivalents and other 41 — — — 41 Trust-owned life insurance — 382 — — 382 Real estate investments 11 — — 35 46 5 5 Special situations — — — 5 5 1 1 Private equity — — — 17 17 3 2 Total $ 207 $ 574 $ — $ 57 $ 838 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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 Target Allocation Actual Allocation As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (a) $ 106 $ 52 $ — $ — $ 158 42 % 38 % International equity (a) 40 63 — — 103 21 23 Fixed income: 28 30 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 — — 40 51 5 6 Special situations (b) — — — 5 5 1 1 Private equity — — — 18 18 3 2 Total $ 168 $ 603 $ — $ 63 $ 834 100 % 100 % (a) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. (b) The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation.
Southern Company Gas [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 periods presented and the benefit obligations as of the measurement date are presented below. Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, Assumptions used to determine net periodic costs: 2016 2016 2015 2014 Pension plans Discount rate – interest costs (a) 3.21 % 4.00 % 4.20 % 5.00 % Discount rate – service costs (a) 4.07 4.80 4.20 5.00 Expected long-term return on plan assets 7.75 7.80 7.80 7.80 Annual salary increase 3.50 3.70 3.70 3.70 Pension band increase (b) 2.00 2.00 2.00 2.00 Other postretirement benefit plans Discount rate – interest costs (a) 2.84 % 3.60 % 4.00 % 4.70 % Discount rate – service costs (a) 3.96 4.70 4.00 4.70 Expected long-term return on plan assets 5.93 6.60 7.80 7.80 Annual salary increase 3.50 3.70 3.70 3.70 (a) Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate. (b) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates of 2.0% for each of 2016 and 2017, in accordance with a March 2014 union agreement. Successor Predecessor Assumptions used to determine benefit obligations: December 31, 2016 December 31, 2015 Pension plans Discount rate 4.39 % 4.6 % Annual salary increase 3.50 3.7 Pension band increase (*) 2.00 2.0 Other postretirement benefit plans Discount rate 4.15 % 4.4 % Annual salary increase 3.50 3.7 (*) Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates of 2.0% for each of 2016 and 2017, in accordance with a March 2014 union agreement.
Schedule of Health Care Cost Trend Rates	The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.60 % 4.50 % 2038 Post-65 medical 8.40 4.50 2038 Post-65 prescription 8.40 4.50 2038
Effect of 1% annual increase or decrease in assumed medical care cost on APBO and service and interest cost components	An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components as follows: 1 Percent Increase 1 Percent Decrease (in millions) Successor – December 31, 2016 Benefit obligation $ 14 $ 12 Service and interest costs — —
Changes in projected benefit obligations and fair value of plan assets	Changes in the projected benefit obligations and the fair value of plan assets for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 were as follows: Successor Predecessor July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 2015 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 1,244 $ 1,067 $ 1,098 Service cost 15 13 28 Interest cost 20 21 45 Benefits paid (31 ) (26 ) (49 ) Actuarial loss (gain) (115 ) 169 (55 ) Balance at end of period 1,133 1,244 1,067 Change in plan assets Fair value of plan assets at beginning of period 837 847 906 Actual return (loss) on plan assets 48 15 (12 ) Employer contributions 129 1 2 Benefits paid (31 ) (26 ) (49 ) Fair value of plan assets at end of period 983 837 847 Accrued liability $ 150 $ 407 $ 220
Schedule of amounts recognized in other comprehensive income (loss)	The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2014: $ 301 $ 76 Net (gain) loss — 22 Reclassification adjustments: Amortization of prior service costs 2 — Amortization of net loss (21 ) (10 ) Total reclassification adjustments (19 ) (10 ) Total change (19 ) 12 Predecessor – Balance at December 31, 2015: $ 282 $ 88 Reclassification adjustments: Amortization of prior service costs 1 — Amortization of net loss (9 ) (4 ) Total reclassification adjustments (8 ) (4 ) Total change (8 ) (4 ) Predecessor – Balance at June 30, 2016: $ 274 $ 84 Successor – Balance at July 1, 2016: $ — $ 368 Net (gain) loss (43 ) (87 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (15 ) Total reclassification adjustments — (14 ) Total change (43 ) (101 ) Successor – Balance at December 31, 2016: $ (43 ) $ 267 The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Predecessor – Balance at December 31, 2014: $ 36 $ 39 Net (gain) loss 2 (8 ) Reclassification adjustments: Amortization of prior service costs — 2 Amortization of net loss (2 ) (3 ) Total reclassification adjustments (2 ) (1 ) Total change — (9 ) Predecessor – Balance at December 31, 2015: $ 36 $ 30 Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss (1 ) (1 ) Total reclassification adjustments (1 ) — Total change (1 ) — Predecessor – Balance at June 30, 2016: $ 35 $ 30 Successor – Balance at July 1, 2016: $ — $ 77 Net (gain) loss (3 ) (23 ) Reclassification adjustments: Amortization of prior service costs — 1 Amortization of net loss — (3 ) Total reclassification adjustments — (2 ) Total change (3 ) (25 ) Successor – Balance at December 31, 2016: $ (3 ) $ 52
Components of net periodic benefit cost	Components of net periodic pension costs for the periods presented were as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 (in millions) (in millions) Service cost $ 15 $ 13 $ 28 $ 24 Interest cost 20 21 45 47 Expected return on plan assets (35 ) (33 ) (65 ) (65 ) Amortization of regulatory assets 13 — — — Amortization: Prior service costs — (1 ) (2 ) (2 ) Net (gain)/loss — 13 31 22 Net periodic pension cost $ 13 $ 13 $ 37 $ 26
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets	Changes in the APBO and the fair value of plan assets for the successor period ended December 31, 2016 and for the predecessor periods ended June 30, 2016 and December 31, 2015 were as follows: Successor Predecessor July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 2015 (in millions) (in millions) Change in benefit obligation Benefit obligation at beginning of period $ 338 $ 318 $ 334 Service cost 1 1 2 Interest cost 5 5 13 Benefits paid (11 ) (11 ) (20 ) Actuarial loss (gain) (26 ) 24 (13 ) Retiree drug subsidy — — 1 Employee contributions 1 1 1 Balance at end of period 308 338 318 Change in plan assets Fair value of plan assets at beginning of period 100 99 99 Actual return (loss) on plan assets 4 1 1 Employee contributions 1 1 1 Employer contributions 11 10 17 Benefits paid (11 ) (11 ) (20 ) Retiree drug subsidy — — 1 Fair value of plan assets at end of year 105 100 99 Accrued liability $ 203 $ 238 $ 219
Amounts included in accumulated other comprehensive income and regulatory assets related to other postretirement benefit plans	Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 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 2017 . Prior Service Cost Net (Gain) Loss (in millions) Successor – Balance at December 31, 2016: Accumulated OCI $ — $ (43 ) Regulatory assets (liabilities) (2 ) 269 Total $ (2 ) $ 226 Predecessor – Balance at December 31, 2015: Accumulated OCI $ (4 ) $ 286 Regulatory assets — 88 Total $ (4 ) $ 374 Estimated amortization in net periodic cost in 2017: Regulatory assets (liabilities) $ 1 $ (21 ) Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is immaterial. Prior Service Cost Net (Gain) Loss (in millions) Successor – Balance at December 31, 2016: Accumulated OCI $ — $ (3 ) Regulatory assets (liabilities) (12 ) 64 Total $ (12 ) $ 61 Predecessor – Balance at December 31, 2015: Accumulated OCI $ — $ 36 Regulatory assets (liabilities) (15 ) 45 Total $ (15 ) $ 81
Fair values of benefit plan assets	For 2016, special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient Total As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Target Allocation Actual Allocation As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 2,010 $ 927 $ — $ — $ 2,937 26 % 29 % International equity (*) 1,231 1,110 — — 2,341 25 22 Fixed income: 23 29 U.S. Treasury, government, and agency bonds — 588 — — 588 Mortgage- and asset-backed securities — 13 — — 13 Corporate bonds — 991 — — 991 Pooled funds — 524 — — 524 Cash equivalents and other 996 2 — — 998 Real estate investments 310 — — 1,152 1,462 14 13 Special situations — — 180 180 3 2 Private equity — — — 549 549 9 5 Total $ 4,547 $ 4,155 $ — $ 1,881 $ 10,583 100 % 100 % (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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 Target Allocation Actual Allocation As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (a) $ 1,632 $ 681 $ — $ — $ 2,313 26 % 30 % International equity (a) 1,190 962 — — 2,152 25 23 Fixed income: 23 23 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 — — 1,185 1,484 14 16 Special situations (b) — — — 160 160 3 2 Private equity — — — 536 536 9 6 Total $ 3,121 $ 4,081 $ — $ 1,881 $ 9,083 100 % 100 % Liabilities: Derivatives $ (1 ) $ — $ — $ — $ (1 ) Total $ 3,120 $ 4,081 $ — $ 1,881 $ 9,082 100 % 100 % (a) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. (b) The 2015 presentation above has been revised to separately reflect special situations, consistent with the 2016 presentation. The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Significant Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Successor – As of December 31, 2016 (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 142 $ 343 $ — $ — $ 485 International equity (*) — 185 — — 185 Fixed income: U.S. Treasury, government, and agency bonds — 85 — — 85 Corporate bonds — 41 — — 41 Pooled funds — 66 — — 66 Cash equivalents and other 12 5 — 83 100 Real estate investments 4 — — 15 19 Private equity — — — 2 2 Total $ 158 $ 725 $ — $ 100 $ 983 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Predecessor – As of December 31, 2015 Pension plans (a) In millions Level 1 Level 2 Level 3 Total % of total Cash $ 4 $ — $ — $ 4 — % Equity securities: U.S. large cap (b) $ 75 $ 199 $ — $ 274 32 % U.S. small cap (b) 57 24 — 81 9 % International companies (c) — 125 — 125 15 % Emerging markets (d) — 28 — 28 3 % Total equity securities $ 132 $ 376 $ — $ 508 59 % Fixed income securities: Corporate bonds (e) $ — $ 91 $ — $ 91 11 % Other (or gov't/muni bonds) — 151 — 151 18 % Total fixed income securities $ — $ 242 $ — $ 242 29 % Other types of investments: Global hedged equity (f) $ — $ — $ 40 $ 40 5 % Absolute return (g) — — 42 42 5 % Private capital (h) — — 20 20 2 % Total other investments $ — $ — $ 102 $ 102 12 % Total assets at fair value $ 136 $ 618 $ 102 $ 856 100 % % of fair value hierarchy 16 % 72 % 12 % 100 % (a) Includes $9 million at December 31, 2015 of medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the other retirement benefits. (b) Includes funds that invest primarily in U.S. common stocks. (c) Includes funds that invest primarily in foreign equity and equity-related securities. (d) Includes funds that invest primarily in common stocks of emerging markets. (e) Includes funds that invest primarily in investment grade debt and fixed income securities. (f) Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or "hedge funds." (g) Includes funds that invest primarily in investment vehicles and commodity pools as a "fund of funds." (h) Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans. The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient Successor – As of December 31, 2016 (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 58 $ — $ — $ 61 International equity (*) — 18 — — 18 Fixed income: Pooled funds — 23 — — 23 Cash equivalents and other 1 — — 2 3 Total $ 4 $ 99 $ — $ 2 $ 105 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Predecessor – As of December 31, 2015 Welfare plans In millions Level 1 Level 2 Level 3 Total % of total Cash $ 1 $ — $ — $ 1 1 % Equity securities: U.S. large cap (a) $ — $ 52 $ — $ 52 58 % U.S. small cap (a) — — — — — % International companies (b) — 15 — 15 17 % Emerging markets (c) — — — — — % Total equity securities $ — $ 67 $ — $ 67 75 % Fixed income securities: Corporate bonds (d) $ — $ 22 $ — $ 22 24 % Other (or gov't/muni bonds) — — — — — % Total fixed income securities $ — $ 22 $ — $ 22 24 % Other types of investments: Global hedged equity (e) $ — $ — $ — $ — — % Absolute return (f) — — — — — % Private capital (g) — — — — — % Total other investments $ — $ — $ — $ — — % Total assets at fair value $ 1 $ 89 $ — $ 90 100 % % of fair value hierarchy 1 % 99 % — % 100 % (a) Includes funds that invest primarily in U.S. common stocks. (b) Includes funds that invest primarily in foreign equity and equity-related securities. (c) Includes funds that invest primarily in common stocks of emerging markets. (d) Includes funds that invest primarily in investment grade debt and fixed income securities. (e) Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or "hedge funds." (f) Includes funds that invest primarily in investment vehicles and commodity pools as a "fund of funds." (g) Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans.
Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the consolidated balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: Successor Predecessor 2016 2015 (in millions) (in millions) Other regulatory assets, deferred $ 267 $ 88 Other deferred charges and assets 58 78 Other current liabilities (2 ) (4 ) Employee benefit obligations (206 ) (294 )
Estimated pension benefit payments	At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 71 2018 72 2019 73 2020 74 2021 74 2022 to 2026 363
Southern Company Gas [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the consolidated balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: Successor Predecessor 2016 2015 (in millions) (in millions) Other regulatory assets, deferred $ 52 $ 30 Employee benefit obligations (203 ) (219 )
Components of net periodic benefit cost	Components of the other postretirement benefit plans' net periodic cost for the periods presented were as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 (in millions) (in millions) Service cost $ 1 $ 1 $ 2 $ 2 Interest cost 5 5 13 15 Expected return on plan assets (3 ) (3 ) (7 ) (7 ) Amortization of regulatory assets 2 — — — Amortization: Prior service costs — (1 ) (3 ) (3 ) Net (gain)/loss — 2 6 6 Net periodic postretirement benefit cost $ 5 $ 4 $ 11 $ 13
Estimated pension benefit payments	Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 20 2018 20 2019 21 2020 22 2021 22 2022 to 2026 111
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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.67 % 4.18 % 5.02 % Discount rate – interest costs 3.90 4.18 5.02 Discount rate – service costs 5.07 4.49 5.02 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.51 % 4.04 % 4.86 % Discount rate – interest costs 3.69 4.04 4.86 Discount rate – service costs 4.96 4.40 4.86 Expected long-term return on plan assets 6.83 7.17 7.34 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.44 % 4.67 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.27 % 4.51 % Annual salary increase 4.46 4.46
Schedule of Health Care Cost Trend Rates	The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 28 $ 24 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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 2,506 $ 2,592 Service cost 57 59 Interest cost 95 106 Benefits paid (109 ) (120 ) Actuarial (gain) loss 114 (131 ) Balance at end of year 2,663 2,506 Change in plan assets Fair value of plan assets at beginning of year 2,279 2,396 Actual return (loss) on plan assets 206 (9 ) Employer contributions 141 12 Benefits paid (109 ) (120 ) Fair value of plan assets at end of year 2,517 2,279 Accrued liability $ (146 ) $ (227 )
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 870 $ 822 Other current liabilities (12 ) (11 ) Employee benefit obligations (134 ) (216 ) Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 86 $ 95 Other regulatory liabilities, deferred (10 ) (13 ) Employee benefit obligations (134 ) (142 )
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, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 15 $ 19 $ 4 Net (gain) loss 61 63 1 Net regulatory assets $ 76 $ 82 Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 10 $ 6 $ 3 Net (gain) loss 860 816 42 Regulatory assets $ 870 $ 822
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, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Net regulatory assets (liabilities): Beginning balance $ 82 $ 54 Net (gain) loss — 25 Change in prior service costs — 8 Reclassification adjustments: Amortization of prior service costs (4 ) (3 ) Amortization of net gain (loss) (2 ) (2 ) Total reclassification adjustments (6 ) (5 ) Total change (6 ) 28 Ending balance $ 76 $ 82 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 822 $ 827 Net (gain) loss 84 56 Change in prior service costs 7 — Reclassification adjustments: Amortization of prior service costs (3 ) (6 ) Amortization of net gain (loss) (40 ) (55 ) Total reclassification adjustments (43 ) (61 ) Total change 48 (5 ) Ending balance $ 870 $ 822
Components of net periodic benefit cost	Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 5 $ 6 $ 5 Interest cost 18 20 20 Expected return on plan assets (25 ) (26 ) (25 ) Net amortization 6 5 4 Net periodic postretirement benefit cost $ 4 $ 5 $ 4 Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 57 $ 59 $ 48 Interest cost 95 106 103 Expected return on plan assets (184 ) (178 ) (168 ) Recognized net (gain) loss 40 55 31 Net amortization 3 6 7 Net periodic pension cost $ 11 $ 48 $ 21
Estimated pension benefit payments	At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 122 2018 127 2019 132 2020 137 2021 142 2022 to 2026 777 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) 2017 $ 32 $ (3 ) $ 29 2018 33 (3 ) 30 2019 34 (4 ) 30 2020 35 (4 ) 31 2021 36 (4 ) 32 2022 to 2026 183 (22 ) 161
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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 505 $ 503 Service cost 5 6 Interest cost 18 20 Benefits paid (28 ) (27 ) Actuarial (gain) loss (1 ) (7 ) Plan amendment — 7 Retiree drug subsidy 2 3 Balance at end of year 501 505 Change in plan assets Fair value of plan assets at beginning of year 363 392 Actual return (loss) on plan assets 23 (6 ) Employer contributions 7 1 Benefits paid (26 ) (24 ) Fair value of plan assets at end of year 367 363 Accrued liability $ (134 ) $ (142 )
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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 46 % 44 % 45 % International equity 22 20 20 Domestic fixed income 24 29 27 Special situations 1 1 1 Real estate investments 4 4 5 Private equity 3 2 2 Total 100 % 100 % 100 %
Fair values of benefit plan assets	The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 477 $ 220 $ — $ — $ 697 International equity (*) 292 264 — — 556 Fixed income: U.S. Treasury, government, and agency bonds — 140 — — 140 Mortgage- and asset-backed securities — 3 — — 3 Corporate bonds — 235 — — 235 Pooled funds — 124 — — 124 Cash equivalents and other 236 1 — — 237 Real estate investments 74 — — 274 348 Special situations — — — 43 43 Private equity — — — 130 130 Total $ 1,079 $ 987 $ — $ 447 $ 2,513 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 51 $ 10 $ — $ — $ 61 International equity (*) 13 12 — — 25 Fixed income: U.S. Treasury, government, and agency bonds — 7 — — 7 Mortgage- and asset-backed securities — — — — — Corporate bonds — 10 — — 10 Pooled funds — 5 — — 5 Cash equivalents and other 14 — — — 14 Trust-owned life insurance — 220 — — 220 Real estate investments 4 — — 12 16 Special situations — — — 2 2 Private equity — — — 6 6 Total $ 82 $ 264 $ — $ 20 $ 366 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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.
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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.65 % 4.18 % 5.02 % Discount rate – interest costs 3.86 4.18 5.02 Discount rate – service costs 5.03 4.49 5.02 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.49 % 4.03 % 4.85 % Discount rate – interest costs 3.67 4.03 4.85 Discount rate – service costs 4.88 4.39 4.85 Expected long-term return on plan assets 6.27 6.48 6.75 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.40 % 4.65 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.23 % 4.49 % Annual salary increase 4.46 4.46
Schedule of Health Care Cost Trend Rates	The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 55 $ 48 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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 3,615 $ 3,781 Service cost 70 73 Interest cost 136 154 Benefits paid (164 ) (188 ) Actuarial (gain) loss 143 (205 ) Balance at end of year 3,800 3,615 Change in plan assets Fair value of plan assets at beginning of year 3,196 3,383 Actual return (loss) on plan assets 288 (13 ) Employer contributions 301 14 Benefits paid (164 ) (188 ) Fair value of plan assets at end of year 3,621 3,196 Accrued liability $ (179 ) $ (419 )
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 1,129 $ 1,076 Other current liabilities (14 ) (13 ) Employee benefit obligations (165 ) (406 ) Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 213 $ 223 Employee benefit obligations (493 ) (496 )
Schedule of amounts recognized in other comprehensive income (loss)	The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 223 $ 213 Net (gain) loss — 9 Change in prior service costs — 12 Reclassification adjustments: Amortization of prior service costs (1 ) — Amortization of net gain (loss) (9 ) (11 ) Total reclassification adjustments (10 ) (11 ) Total change (10 ) 10 Ending balance $ 213 $ 223
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, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 17 $ 8 $ 3 Net (gain) loss 1,112 1,068 57 Regulatory assets $ 1,129 $ 1,076 Presented below are the amounts included in regulatory assets at December 31, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 6 $ 8 $ 1 Net (gain) loss 207 215 8 Regulatory assets $ 213 $ 223
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, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 1,076 $ 1,102 Net (gain) loss 99 59 Change in prior service costs 14 — Reclassification adjustments: Amortization of prior service costs (5 ) (9 ) Amortization of net gain (loss) (55 ) (76 ) Total reclassification adjustments (60 ) (85 ) Total change 53 (26 ) Ending balance $ 1,129 $ 1,076
Components of net periodic benefit cost	Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 70 $ 73 $ 62 Interest cost 136 154 153 Expected return on plan assets (258 ) (251 ) (228 ) Recognized net (gain) loss 55 76 41 Net amortization 5 9 10 Net periodic pension cost $ 8 $ 61 $ 38 Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 6 $ 7 $ 6 Interest cost 30 34 34 Expected return on plan assets (22 ) (24 ) (25 ) Net amortization 10 11 2 Net periodic postretirement benefit cost $ 24 $ 28 $ 17
Estimated pension benefit payments	At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 184 2018 190 2019 196 2020 202 2021 206 2022 to 2026 1,126
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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 854 $ 864 Service cost 6 7 Interest cost 30 34 Benefits paid (45 ) (45 ) Actuarial (gain) loss (1 ) (22 ) Plan amendment — 12 Retiree drug subsidy 3 4 Balance at end of year 847 854 Change in plan assets Fair value of plan assets at beginning of year 358 395 Actual return (loss) on plan assets 21 (6 ) Employer contributions 17 10 Benefits paid (42 ) (41 ) Fair value of plan assets at end of year 354 358 Accrued liability $ (493 ) $ (496 )
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) 2017 $ 54 $ (4 ) $ 50 2018 56 (5 ) 51 2019 58 (5 ) 53 2020 59 (5 ) 54 2021 60 (6 ) 54 2022 to 2026 303 (32 ) 271
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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 36 % 35 % 34 % International equity 24 24 27 Domestic fixed income 33 35 25 Global fixed income 8 Special situations 1 1 — Real estate investments 4 4 4 Private equity 2 1 2 Total 100 % 100 % 100 %
Fair values of benefit plan assets	The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 45 $ 9 $ — $ — $ 54 International equity (*) 11 37 — — 48 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Mortgage- and asset-backed securities — — — — — Corporate bonds — 9 — — 9 Pooled funds — 38 — — 38 Cash equivalents and other 15 — — — 15 Trust-owned life insurance — 162 — — 162 Real estate investments 3 — — 11 14 Special situations — — — 2 2 Private equity — — — 5 5 Total $ 74 $ 260 $ — $ 18 $ 352 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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. The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 686 $ 317 $ — $ — $ 1,003 International equity (*) 420 380 — — 800 Fixed income: U.S. Treasury, government, and agency bonds — 201 — — 201 Mortgage- and asset-backed securities — 4 — — 4 Corporate bonds — 338 — — 338 Pooled funds — 179 — — 179 Cash equivalents and other 340 1 — — 341 Real estate investments 106 — — 394 500 Special situations — — — 61 61 Private equity — — — 188 188 Total $ 1,552 $ 1,420 $ — $ 643 $ 3,615 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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.
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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.71 % 4.18 % 5.02 % Discount rate – interest costs 3.97 4.18 5.02 Discount rate – service costs 5.04 4.48 5.02 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.51 % 4.04 % 4.86 % Discount rate – interest costs 3.68 4.04 4.86 Discount rate – service costs 4.88 4.38 4.86 Expected long-term return on plan assets 8.05 8.07 8.08 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.46 % 4.71 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.25 % 4.51 % Annual salary increase 4.46 4.46
Schedule of Health Care Cost Trend Rates	The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 480 $ 491 Service cost 12 12 Interest cost 19 20 Benefits paid (17 ) (20 ) Actuarial (gain) loss 23 (23 ) Balance at end of year 517 480 Change in plan assets Fair value of plan assets at beginning of year 420 435 Actual return (loss) on plan assets 39 4 Employer contributions 49 1 Benefits paid (17 ) (20 ) Fair value of plan assets at end of year 491 420 Accrued liability $ (26 ) $ (60 )
Schedule of amounts recognized in other comprehensive income (loss)	The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Net regulatory assets (liabilities): Beginning balance $ 5 $ 2 Net (gain) loss 2 1 Change in prior service costs — 2 Total change 2 3 Ending balance $ 7 $ 5
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, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 3 $ 2 $ 1 Net (gain) loss 150 140 7 Regulatory assets $ 153 $ 142
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, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 142 $ 146 Net (gain) loss 16 6 Change in prior service costs 2 — Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (6 ) (9 ) Total reclassification adjustments (7 ) (10 ) Total change 11 (4 ) Ending balance $ 153 $ 142
Estimated pension benefit payments	At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 20 2018 22 2019 23 2020 24 2021 26 2022 to 2026 149
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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 81 $ 78 Service cost 1 1 Interest cost 3 3 Benefits paid (4 ) (4 ) Actuarial (gain) loss 2 (1 ) Plan amendment — 4 Balance at end of year 83 81 Change in plan assets Fair value of plan assets at beginning of year 17 18 Actual return (loss) on plan assets 2 — Employer contributions 3 3 Benefits paid (4 ) (4 ) Fair value of plan assets at end of year 18 17 Accrued liability $ (65 ) $ (64 )
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) 2017 $ 5 $ — $ 5 2018 5 — 5 2019 6 (1 ) 5 2020 6 (1 ) 5 2021 6 (1 ) 5 2022 to 2026 30 (3 ) 27
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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 25 % 28 % 29 % International equity 24 21 22 Domestic fixed income 25 31 25 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 %
Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 153 $ 142 Other current liabilities (1 ) (1 ) Employee benefit obligations (25 ) (59 )
Components of net periodic benefit cost	Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 12 $ 12 $ 10 Interest cost 19 20 19 Expected return on plan assets (34 ) (32 ) (28 ) Recognized net (gain) loss 6 9 5 Net amortization 1 1 1 Net periodic pension cost $ 4 $ 10 $ 7
Fair values of benefit plan assets	The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 93 $ 43 $ — $ — $ 136 International equity (*) 57 52 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 27 — — 27 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 47 — — 47 Pooled funds — 24 — — 24 Cash equivalents and other 46 — — — 46 Real estate investments 14 — — 53 67 Special situations — — — 8 8 Private equity — — — 25 25 Total $ 210 $ 194 $ — $ 86 $ 490 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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.
Gulf Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 11 $ 10 Other current liabilities (1 ) (1 ) Other regulatory liabilities, deferred (4 ) (5 ) Employee benefit obligations (64 ) (63 )
Components of net periodic benefit cost	Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (1 ) (1 ) (1 ) Net periodic postretirement benefit cost $ 3 $ 3 $ 3
Fair values of benefit plan assets	The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 3 $ 2 $ — $ — $ 5 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 1 — — 1 Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 8 $ 8 $ — $ 3 $ 19 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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 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.
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: 2016 2015 2014 Pension plans Discount rate – benefit obligations 4.69 % 4.17 % 5.01 % Discount rate – interest costs 3.97 4.17 5.01 Discount rate – service costs 5.04 4.49 5.01 Expected long-term return on plan assets 8.20 8.20 8.20 Annual salary increase 4.46 3.59 3.59 Other postretirement benefit plans Discount rate – benefit obligations 4.47 % 4.03 % 4.85 % Discount rate – interest costs 3.66 4.03 4.85 Discount rate – service costs 4.88 4.38 4.85 Expected long-term return on plan assets 7.07 7.23 7.30 Annual salary increase 4.46 3.59 3.59 Assumptions used to determine benefit obligations: 2016 2015 Pension plans Discount rate 4.44 % 4.69 % Annual salary increase 4.46 4.46 Other postretirement benefit plans Discount rate 4.22 % 4.47 % Annual salary increase 4.46 4.46
Schedule of Health Care Cost Trend Rates	The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows: Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached Pre-65 6.50 % 4.50 % 2025 Post-65 medical 5.00 4.50 2025 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, 2016 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation $ 5 $ 4 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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 500 $ 513 Service cost 13 13 Interest cost 19 21 Benefits paid (20 ) (22 ) Actuarial (gain) loss 22 (25 ) Balance at end of year 534 500 Change in plan assets Fair value of plan assets at beginning of year 430 446 Actual return (loss) on plan assets 39 4 Employer contributions 50 2 Benefits paid (20 ) (22 ) Fair value of plan assets at end of year 499 430 Accrued liability $ (35 ) $ (70 )
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's other postretirement benefit plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 21 $ 21 Other regulatory liabilities, deferred (2 ) (3 ) Employee benefit obligations (74 ) (74 )
Schedule of amounts recognized in other comprehensive income (loss)	The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Net regulatory assets (liabilities): Beginning balance $ 18 $ 16 Net (gain) loss 2 — Change in prior service costs — 3 Reclassification adjustments: Amortization of net gain (loss) (1 ) (1 ) Total reclassification adjustments (1 ) (1 ) Total change 1 2 Ending balance $ 19 $ 18
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, 2016 and 2015 are presented in the following table: 2016 2015 (in millions) Regulatory assets: Beginning balance $ 144 $ 151 Net (gain) loss 16 4 Change in prior service costs 2 — Reclassification adjustments: Amortization of prior service costs (1 ) (1 ) Amortization of net gain (loss) (7 ) (10 ) Total reclassification adjustments (8 ) (11 ) Total change 10 (7 ) Ending balance $ 154 $ 144
Estimated pension benefit payments	At December 31, 2016 , estimated benefit payments were as follows: Benefit Payments (in millions) 2017 $ 22 2018 23 2019 24 2020 26 2021 27 2022 to 2026 154
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, 2016 and 2015 were as follows: 2016 2015 (in millions) Change in benefit obligation Benefit obligation at beginning of year $ 97 $ 96 Service cost 1 1 Interest cost 3 4 Benefits paid (6 ) (5 ) Actuarial (gain) loss 1 (1 ) Plan amendment — 1 Retiree drug subsidy 1 1 Balance at end of year 97 97 Change in plan assets Fair value of plan assets at beginning of year 23 24 Actual return (loss) on plan assets 1 — Employer contributions 4 3 Benefits paid (5 ) (4 ) Fair value of plan assets at end of year 23 23 Accrued liability $ (74 ) $ (74 )
Summary of estimation of future benefit payments and subsidy receipts based on assumptions used to measure accumulated benefit obligation for postretirement plans	Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: Benefit Payments Subsidy Receipts Total (in millions) 2017 $ 6 $ (1 ) $ 5 2018 6 (1 ) 5 2019 7 (1 ) 6 2020 7 (1 ) 6 2021 7 (1 ) 6 2022 to 2026 36 (1 ) 35
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, 2016 and 2015 , along with the targeted mix of assets for each plan, is presented below: Target 2016 2015 Pension plan assets: Domestic equity 26 % 29 % 30 % International equity 25 22 23 Fixed income 23 29 23 Special situations 3 2 2 Real estate investments 14 13 16 Private equity 9 5 6 Total 100 % 100 % 100 % Other postretirement benefit plan assets: Domestic equity 21 % 23 % 24 % International equity 20 18 18 Domestic fixed income 38 43 38 Special situations 3 2 2 Real estate investments 11 10 13 Private equity 7 4 5 Total 100 % 100 % 100 %
Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in balance sheets related to benefit plans	Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company's pension plans consist of the following: 2016 2015 (in millions) Other regulatory assets, deferred $ 154 $ 144 Other current liabilities (3 ) (3 ) Employee benefit obligations (32 ) (67 )
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, 2016 and 2015 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 2017 . 2016 2015 Estimated Amortization in 2017 (in millions) Prior service cost $ 3 $ 2 $ 1 Net (gain) loss 151 142 7 Regulatory assets $ 154 $ 144
Components of net periodic benefit cost	Components of net periodic pension cost were as follows: 2016 2015 2014 (in millions) Service cost $ 13 $ 13 $ 10 Interest cost 19 21 20 Expected return on plan assets (35 ) (33 ) (29 ) Recognized net (gain) loss 7 10 5 Net amortization 1 1 1 Net periodic pension cost $ 5 $ 12 $ 7
Fair values of benefit plan assets	The fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 95 $ 44 $ — $ — $ 139 International equity (*) 58 51 — — 109 Fixed income: U.S. Treasury, government, and agency bonds — 28 — — 28 Mortgage- and asset-backed securities — 1 — — 1 Corporate bonds — 46 — — 46 Pooled funds — 25 — — 25 Cash equivalents and other 47 — — — 47 Real estate investments 15 — — 54 69 Special situations — — — 8 8 Private equity — — — 26 26 Total $ 215 $ 195 $ — $ 88 $ 498 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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.
Mississippi Power [Member] | Other postretirement benefit plans
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	Approximately $19 million and $18 million was included in net regulatory assets at December 31, 2016 and 2015 , respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is $1 million .
Components of net periodic benefit cost	Components of the other postretirement benefit plans' net periodic cost were as follows: 2016 2015 2014 (in millions) Service cost $ 1 $ 1 $ 1 Interest cost 3 4 4 Expected return on plan assets (1 ) (2 ) (2 ) Net amortization 1 1 — Net periodic postretirement benefit cost $ 4 $ 4 $ 3
Fair values of benefit plan assets	The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Domestic equity (*) $ 4 $ 2 $ — $ — $ 6 International equity (*) 2 2 — — 4 Fixed income: U.S. Treasury, government, and agency bonds — 5 — — 5 Mortgage- and asset-backed securities — — — — — Corporate bonds — 2 — — 2 Pooled funds — 1 — — 1 Cash equivalents and other 2 — — — 2 Real estate investments 1 — — 2 3 Private equity — — — 1 1 Total $ 9 $ 12 $ — $ 3 $ 24 (*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. 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, 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.

Contingencies and Regulatory 35

Contingencies and Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2016
Loss Contingencies [Line Items]
Current cost estimate and actual costs incurred	As of December 31, 2016, in addition to the $2.76 billion of costs above the Mississippi PSC's $2.88 billion cost cap that have been recognized as a charge to income, Mississippi Power had incurred approximately $1.99 billion in costs subject to the cost cap and approximately $1.46 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following: Cost Category Actual Costs (in billions) Gasifiers and Gas Clean-up Facilities $ 1.88 Lignite Mine Facility 0.31 CO 2 Pipeline Facilities 0.11 Combined Cycle and Common Facilities 0.16 AFUDC 0.69 General exceptions 0.07 Plant inventory 0.03 Lignite inventory 0.08 Regulatory and other deferred assets 0.12 Subtotal 3.45 Additional DOE Grants (0.14 ) Total $ 3.31 Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under " Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order "), and actual costs incurred as of December 31, 2016 , all of which include 100% of the costs for the Kemper IGCC, are as follows: Cost Category 2010 Project Estimate (a) Current Cost Estimate (b) Actual Costs (in billions) Plant Subject to Cost Cap (c)(e) $ 2.40 $ 5.64 $ 5.44 Lignite Mine and Equipment 0.21 0.23 0.23 CO 2 Pipeline Facilities 0.14 0.11 0.11 AFUDC (d) 0.17 0.79 0.75 Combined Cycle and Related Assets Placed in Service – Incremental (e) — 0.04 0.04 General Exceptions 0.05 0.10 0.09 Deferred Costs (e) — 0.22 0.21 Additional DOE Grants (f) — (0.14 ) (0.14 ) Total Kemper IGCC (g) $ 2.97 $ 6.99 $ 6.73 (a) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO 2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. (b) Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. (c) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , net of the Initial DOE Grants and excluding 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 Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). 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. (d) Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in " Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order ." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. (e) Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016 . The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016 . See " Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities " herein for additional information. (f) On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. (g) The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 6 under "Capital Leases" and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information.
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 discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of December 31, 2016, all of which include 100% of the costs for the Kemper IGCC, are as follows: Cost Category 2010 Project Estimate (a) Current Cost Estimate (b) Actual Costs (in billions) Plant Subject to Cost Cap (c)(e) $ 2.40 $ 5.64 $ 5.44 Lignite Mine and Equipment 0.21 0.23 0.23 CO 2 Pipeline Facilities 0.14 0.11 0.11 AFUDC (d) 0.17 0.79 0.75 Combined Cycle and Related Assets Placed in Service – Incremental (e) — 0.04 0.04 General Exceptions 0.05 0.10 0.09 Deferred Costs (e) — 0.22 0.21 Additional DOE Grants (f) — (0.14 ) (0.14 ) Total Kemper IGCC (g) $ 2.97 $ 6.99 $ 6.73 (a) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO 2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. (b) Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. (c) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion , net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). 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. (d) The Company's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also 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. (e) Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. (f) On April 8, 2016, the Company received approximately $137 million in Additional DOE Grants, which are expected to be used to reduce future rate impacts for customers. (g) The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 under "Fuel Inventory," Note 6 under "Capital Leases," and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information. As of December 31, 2016, in addition to the $2.76 billion of costs above the Mississippi PSC's $2.88 billion cost cap that have been recognized as a charge to income, the Company had incurred approximately $1.99 billion in costs subject to the cost cap and approximately $1.46 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following: Cost Category Actual Costs (in billions) Gasifiers and Gas Clean-up Facilities $ 1.88 Lignite Mine Facility 0.31 CO 2 Pipeline Facilities 0.11 Combined Cycle and Common Facilities 0.16 AFUDC 0.69 General exceptions 0.07 Plant inventory 0.03 Lignite inventory 0.08 Regulatory and other deferred assets 0.12 Subtotal 3.45 Additional DOE Grants (0.14 ) Total $ 3.31
Regulatory Asset Off Balance Sheet | Southern Company Gas [Member]
Loss Contingencies [Line Items]
Schedule of unrecognized ratemaking amounts	The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers. Successor Predecessor December 31, 2016 December 31, 2015 (in millions) (in millions) Atlanta Gas Light $ 110 $ 103 Virginia Natural Gas 11 12 Elizabethtown Gas 6 4 Nicor Gas 2 3 Total $ 129 $ 122

Joint Ownership Agreements (Tab

Joint Ownership Agreements (Tables)	12 Months Ended
	Dec. 31, 2016
Jointly Owned Utility Plant Interests [Line Items]
Schedule of percentage ownership and investment in jointly-owned facilities	At December 31, 2016 , 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 % $ 3,545 $ 2,111 $ 74 Plant Hatch (nuclear) 50.1 1,297 585 81 Plant Miller (coal) Units 1 and 2 91.8 1,657 587 23 Plant Scherer (coal) Units 1 and 2 8.4 258 90 3 Plant Wansley (coal) 53.5 1,046 308 12 Rocky Mountain (pumped storage) 25.4 181 129 — Plant Stanton (combined cycle) Unit A 65.0 155 58 —
Temporary Equity	The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) Balance at December 31, 2013 $ 375 Issued — Redeemed — Balance at December 31, 2014 375 Issued — Redeemed (262 ) Other 5 Balance at December 31, 2015 118 Issued — Redeemed — Balance at December 31, 2016 $ 118
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 an associated gas pipeline, the Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2016 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) $ 168 $ 66 $ 1 Plant Miller Units 1 and 2 1,320 91.84 % (2) 1,657 587 23 (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, 2016 , 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 % $ 3,545 $ 2,111 $ 74 Plant Hatch (nuclear) 50.1 1,297 585 81 Plant Wansley (coal) 53.5 1,046 308 12 Plant Scherer (coal) Units 1 and 2 8.4 258 90 3 Unit 3 75.0 1,203 458 23 Rocky Mountain (pumped storage) 25.4 181 129 —
Gulf Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Schedule of percentage ownership and investment in jointly-owned facilities	At December 31, 2016 , 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 $ 398 $ 680 Accumulated depreciation 143 202 Construction work in progress 7 7 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, 2016 , 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 % $ 165 $ 48 $ — Daniel Units 1 and 2 50 % $ 695 $ 173 $ 15
Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Temporary Equity	The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below: Predecessor – (in millions) Balance at December 31, 2015 $ — Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest 46 Net income attributable to noncontrolling interest 14 Distribution to noncontrolling interest (19 ) Balance at June 30, 2016 $ 41 Successor – (in millions) Balance at July 1, 2016 $ 174 Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable (174 ) Balance at December 31, 2016 $ —
Equity Method Investments	The carrying amounts of the Company's equity method investments as of December 31, 2016 and 2015 and related income from those investments for the successor period ended December 31, 2016 and predecessor periods ended June 30, 2016 and December 31, 2015 and 2014 were as follows: Balance Sheet Information Successor Predecessor December 31, 2016 December 31, 2015 (in millions) (in millions) SNG $ 1,394 $ — Triton 44 49 Horizon Pipeline 30 14 PennEast Pipeline 22 9 Atlantic Coast Pipeline 33 7 Pivotal JAX LNG, LLC 16 — Other 2 1 Total $ 1,541 $ 80 Income Statement Information Successor Predecessor July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 2015 2014 (in millions) (in millions) SNG $ 56 $ — $ — $ — Triton 2 1 4 6 Horizon Pipeline 1 1 2 2 Atlantic Coast Pipeline 1 — — — Total $ 60 $ 2 $ 6 $ 8 Selected financial information of SNG since the Company's September 1, 2016 acquisition of a 50% equity interest is as follows: Balance Sheet Information As of December 31, 2016 (in millions) Current assets $ 95 Property, plant, and equipment 2,451 Deferred charges and other assets 129 Total Assets $ 2,675 Current liabilities $ 588 Long-term debt 706 Other deferred charges and other liabilities 22 Total Liabilities $ 1,316 Total Stockholders' Equity 1,359 Total Liabilities and Stockholders' Equity $ 2,675 Income Statement Information September 1, 2016 (in millions) Revenues $ 230 Operating income $ 138 Net income $ 115

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal — Current $ 1,184 $ (177 ) $ 175 Deferred (342 ) 1,266 695 842 1,089 870 State — Current (108 ) (33 ) 93 Deferred 217 138 14 109 105 107 Total $ 951 $ 1,194 $ 977
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: 2016 2015 (in millions) Deferred tax liabilities — Accelerated depreciation $ 15,392 $ 12,767 Property basis differences 2,708 1,603 Leveraged lease basis differences 314 308 Employee benefit obligations 737 579 Premium on reacquired debt 89 95 Regulatory assets associated with employee benefit obligations 1,584 1,378 Regulatory assets associated with AROs 1,781 1,422 Other 907 793 Total 23,512 18,945 Deferred tax assets — Federal effect of state deferred taxes 597 479 Employee benefit obligations 1,868 1,720 Over recovered fuel clause 66 104 Other property basis differences 401 695 Deferred costs 100 83 ITC carryforward 1,974 770 Federal NOL carryforward 1,084 38 Unbilled revenue 92 111 Other comprehensive losses 152 85 AROs 1,732 1,482 Estimated Loss on Kemper IGCC 484 451 Deferred state tax assets 266 222 Other 679 443 Total 9,495 6,683 Valuation allowance (23 ) (4 ) Total deferred income taxes 14,040 12,266 Portion included in accumulated deferred tax assets (52 ) (56 ) Accumulated deferred income taxes $ 14,092 $ 12,322
Summary of operating loss carryforward	At December 31, 2016, the state NOL carryforwards for Southern Company's subsidiaries were as follows: Jurisdiction NOL Carryforwards Net State Income Tax Benefit Tax Year NOL Begins Expiring (in millions) Mississippi $ 3,448 $ 112 2032 Oklahoma 839 31 2036 Georgia 685 25 2019 New York 229 11 2036 New York City 209 12 2036 Florida 198 7 2034 Other states 146 5 Various Total $ 5,754 $ 203
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 2.1 1.9 2.3 Employee stock plans dividend deduction (1.2 ) (1.2 ) (1.4 ) Non-deductible book depreciation 0.9 1.2 1.4 AFUDC-Equity (2.0 ) (2.2 ) (2.9 ) ITC basis difference (5.0 ) (1.5 ) (1.6 ) Federal PTCs (1.2 ) — — Amortization of ITC (0.9 ) (0.5 ) (0.5 ) Other (0.4 ) 0.2 0.2 Effective income tax rate 27.3 % 32.9 % 32.5 %
Changes in unrecognized tax benefits	Changes during the year in unrecognized tax benefits were as follows: 2016 2015 2014 (in millions) Unrecognized tax benefits at beginning of year $ 433 $ 170 $ 7 Tax positions increase from current periods 45 43 64 Tax positions increase from prior periods 21 240 102 Tax positions decrease from prior periods (15 ) (20 ) (3 ) Balance at end of year $ 484 $ 433 $ 170
Impact on effective tax rate	The impact on Southern Company's effective tax rate, if recognized, is as follows: 2016 2015 2014 (in millions) Tax positions impacting the effective tax rate $ 20 $ 10 $ 10 Tax positions not impacting the effective tax rate 464 423 160 Balance of unrecognized tax benefits $ 484 $ 433 $ 170
Alabama Power [Member]
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal — Current $ 103 $ 110 $ 198 Deferred 339 320 225 442 430 423 State — Current 20 8 44 Deferred 69 68 45 89 76 89 Total $ 531 $ 506 $ 512
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: 2016 2015 (in millions) Deferred tax liabilities — Accelerated depreciation $ 4,307 $ 3,917 Property basis differences 456 456 Premium on reacquired debt 26 28 Employee benefit obligations 201 200 Regulatory assets associated with employee benefit obligations 393 375 Asset retirement obligations 289 289 Regulatory assets associated with asset retirement obligations 347 312 Other 179 175 Total 6,198 5,752 Deferred tax assets — Federal effect of state deferred taxes 266 242 Unbilled fuel revenue 36 39 Storm reserve 21 23 Employee benefit obligations 427 407 Other comprehensive losses 19 20 Asset retirement obligations 636 600 Other 139 180 Total 1,544 1,511 Accumulated deferred income taxes, net $ 4,654 $ 4,241
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 4.2 3.8 4.4 Non-deductible book depreciation 1.0 1.2 1.1 AFUDC equity (0.7) (1.6) (1.3) Other (0.7) — (0.2) Effective income tax rate 38.8% 38.4% 39.0%
Georgia Power [Member]
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal – Current $ 391 $ 515 $ 295 Deferred 319 176 366 710 691 661 State – Current 6 81 82 Deferred 64 (3 ) (14 ) 70 78 68 Total $ 780 $ 769 $ 729
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: 2016 2015 (in millions) Deferred tax liabilities – Accelerated depreciation $ 5,266 $ 4,909 Property basis differences 957 1,003 Employee benefit obligations 428 310 Premium on reacquired debt 56 61 Regulatory assets – Storm damage reserves 83 37 Employee benefit obligations 546 528 Asset retirement obligations 726 545 Retired assets 55 58 Asset retirement obligations 182 161 Other 83 92 Total 8,382 7,704 Deferred tax assets – Federal effect of state deferred taxes 173 150 Employee benefit obligations 661 642 Other property basis differences 105 88 Other deferred costs 100 83 State investment tax credit carryforward 201 216 Federal tax credit carryforward 84 3 Unbilled fuel revenue 47 47 Regulatory liabilities associated with asset retirement obligations 33 60 Asset retirement obligations 908 706 Other 70 82 Total 2,382 2,077 Accumulated deferred income taxes $ 6,000 $ 5,627
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction 2.1 2.5 2.2 Non-deductible book depreciation 0.8 1.2 1.3 AFUDC equity (0.8 ) (0.7 ) (0.8 ) Other (0.4 ) (0.4 ) (0.7 ) Effective income tax rate 36.7 % 37.6 % 37.0 %
Gulf Power [Member]
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal - Current $ 34 $ (3 ) $ 23 Deferred 45 80 52 79 77 75 State - Current — 5 — Deferred 12 10 13 12 15 13 Total $ 91 $ 92 $ 88
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: 2016 2015 (in millions) Deferred tax liabilities- Accelerated depreciation $ 834 $ 812 Property basis differences 123 133 Pension and other employee benefits 58 39 Regulatory assets 45 16 Regulatory assets associated with employee benefit obligations 65 59 Regulatory assets associated with asset retirement obligations 55 40 Other 12 10 Total 1,192 1,109 Deferred tax assets- Federal effect of state deferred taxes 37 33 Postretirement benefits 26 26 Pension and other employee benefits 72 65 Property reserve 17 15 Asset retirement obligations 55 40 Alternative minimum tax carryforward 18 18 Other 19 19 Total 244 216 Accumulated deferred income taxes $ 948 $ 893
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.9 3.5 Non-deductible book depreciation 0.6 0.5 0.4 Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.1) AFUDC equity — (1.8) (1.8) Other, net 0.6 (0.6) 0.1 Effective income tax rate 39.5% 36.9% 37.1%
Mississippi Power [Member]
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal — Current $ (31 ) $ (768 ) $ (431 ) Deferred (60 ) 704 183 (91 ) (64 ) (248 ) State — Current (6 ) (81 ) 1 Deferred (7 ) 73 (38 ) (13 ) (8 ) (37 ) Total $ (104 ) $ (72 ) $ (285 )
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: 2016 2015 (in millions) Deferred tax liabilities — Accelerated depreciation $ 386 $ 1,618 Property basis difference 852 — Regulatory assets associated with AROs 72 71 Pensions and other benefits 49 30 Regulatory assets associated with employee benefit obligations 70 66 Regulatory assets associated with the Kemper IGCC 82 86 Rate differential 144 115 Other 125 176 Total 1,780 2,162 Deferred tax assets — Fuel clause over recovered 26 51 Estimated loss on Kemper IGCC 484 451 Pension and other benefits 96 92 Federal NOL 109 17 Property insurance 27 25 Premium on long-term debt 14 18 AROs 72 71 Property basis difference — 451 Deferred state tax assets 113 152 Deferred federal tax assets 31 31 Federal effect of state deferred taxes 19 8 Other 33 33 Total 1,024 1,400 Total deferred tax liabilities, net 756 762 Accumulated deferred income taxes $ 756 $ 762
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate (35.0 )% (35.0 )% (35.0 )% State income tax, net of federal deduction (5.7 ) (6.3 ) (4.0 ) Non-deductible book depreciation 0.7 1.3 0.1 AFUDC-equity (28.5 ) (49.6 ) (7.8 ) Other — (2.9 ) 0.1 Effective income tax rate (benefit rate) (68.5 )% (92.5 )% (46.6 )%
Changes in unrecognized tax benefits	Changes during the year in unrecognized tax benefits were as follows: 2016 2015 2014 (in millions) Unrecognized tax benefits at beginning of year $ 421 $ 165 $ 4 Tax positions increase from current periods 26 32 58 Tax positions increase from prior periods 18 224 103 Balance at end of year $ 465 $ 421 $ 165
Impact on effective tax rate	The impact on the Company's effective tax rate, if recognized, is as follows: 2016 2015 2014 (in millions) Tax positions impacting the effective tax rate $ 1 $ (2 ) $ 4 Tax positions not impacting the effective tax rate 464 423 161 Balance of unrecognized tax benefits $ 465 $ 421 $ 165
Accrued interest for unrecognized tax benefits	Accrued interest for unrecognized tax benefits was as follows: 2016 2015 2014 (in millions) Interest accrued at beginning of year $ 13 $ 3 $ 1 Interest accrued during the year 15 10 2 Balance at end of year $ 28 $ 13 $ 3
Southern Power [Member]
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions are as follows: 2016 2015 2014 (in millions) Federal — Current (*) $ 928 $ 12 $ 179 Deferred (*) (1,098 ) 10 (166 ) (170 ) 22 13 State — Current (60 ) (32 ) (14 ) Deferred 35 31 (2 ) (25 ) (1 ) (16 ) Total $ (195 ) $ 21 $ (3 ) (*) ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $1.13 billion for 2016 , $246 million for 2015 , and $305 million for 2014. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits.
Tax effects between the carrying amounts of assets and liabilities	The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2016 2015 Deferred tax liabilities — Accelerated depreciation and other property basis differences $ 2,440 $ 1,364 Levelized capacity revenues 28 22 Other 27 7 Total deferred income tax liabilities 2,495 1,393 Deferred tax assets — Federal effect of state deferred taxes 53 40 Basis difference on ITCs 292 149 Alternative minimum tax carryforward 15 15 Unrealized tax credits 1,685 551 Federal net operating loss (NOL) 808 9 Deferred state tax assets 60 13 Other partnership basis differences 16 3 Other 8 14 Total deferred income tax assets 2,937 794 Valuation Allowance — (2 ) Net deferred income tax assets 2,937 792 Total deferred income tax asset (liability) $ 442 $ (601 ) Recognized in the consolidated balance sheets: Accumulated deferred income taxes – assets $ 594 $ — Accumulated deferred income taxes – liability $ (152 ) $ (601 )
Summary of operating loss carryforward	The state NOL carryforwards by jurisdiction were as follows: Jurisdiction NOL Carryforwards Net State Income Tax Benefit Tax Year NOL Expires (in millions) Oklahoma $ 838 $ 32 2035 Florida 185 7 2033 Other states 7 1 2029 through 2035 Balance at year end $ 1,030 $ 40
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal deduction (9.1 ) (0.3 ) (6.0 ) Amortization of ITC (20.6 ) (5.0 ) (4.3 ) ITC basis difference (89.0 ) (21.5 ) (27.7 ) Production tax credits (23.3 ) (0.6 ) — Noncontrolling interests (6.2 ) (1.7 ) (0.3 ) Other 4.6 2.5 1.4 Effective income tax rate (benefit) (108.6 )% 8.4 % (1.9 )%
Changes in unrecognized tax benefits	Changes during the year in unrecognized tax benefits were as follows: 2016 2015 2014 (in millions) Balance at beginning of year $ 8 $ 5 $ 2 Tax positions increase from current periods 17 9 5 Tax positions decrease from prior periods (8 ) (6 ) (2 ) Balance at end of year $ 17 $ 8 $ 5
Southern Company Gas [Member]
Income Tax Disclosure [Line Items]
Details of income tax provisions	Details of income tax provisions for the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 are as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 (in millions) (in millions) Federal — Current $ — $ 67 $ (13 ) $ 111 Deferred 65 8 198 184 65 75 185 295 State — Current (16 ) 12 10 38 Deferred 27 — 18 17 11 12 28 55 Total $ 76 $ 87 $ 213 $ 350
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: Successor Predecessor 2016 2015 (in millions) (in millions) Deferred tax liabilities — Accelerated depreciation $ 1,954 $ 1,820 Property basis differences 311 283 Regulatory assets associated with employee benefit obligations 125 44 Other 164 215 Total 2,554 2,362 Deferred tax assets — Federal net operating loss 59 — Federal effect of state deferred taxes 42 62 Employee benefit obligations 165 164 Other 332 212 Total 598 438 Less valuation allowances (19 ) (19 ) Total, net of valuation allowances 579 419 Accumulated deferred income taxes, net $ 1,975 $ 1,943
Schedule of effective income tax reconciliation	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, 2016 2016 2015 2014 Federal statutory rate 35.0% 35.0% 35.0% 35.0% State income tax, net of federal 4.0 3.5 3.4 3.8 Other 1.0 (0.9) (2.0) (1.2) Effective income tax rate 40.0% 37.6% 36.4% 37.6%

Financing (Tables)

Financing (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 (in millions) Senior notes $ 1,995 $ 1,810 Other long-term debt 485 829 Pollution control revenue bonds (*) 76 4 Capitalized leases 32 32 Unamortized debt issuance expense (1 ) (1 ) Total $ 2,587 $ 2,674 (*) Includes $40 million of pollution control revenue bonds classified as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028.
Temporary Equity	The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) Balance at December 31, 2013 $ 375 Issued — Redeemed — Balance at December 31, 2014 375 Issued — Redeemed (262 ) Other 5 Balance at December 31, 2015 118 Issued — Redeemed — Balance at December 31, 2016 $ 118
Credit arrangements with banks	At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year Company 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 35 500 800 1,335 1,335 — — — 35 Georgia Power — — 1,750 1,750 1,732 — — — — Gulf Power 85 195 — 280 280 45 — 25 60 Mississippi Power 173 — — 173 150 — 13 13 160 Southern Power Company (b) — — 600 600 522 — — — — Southern Company Gas (c) 75 1,925 — 2,000 1,949 — — — 75 Other 55 — — 55 55 20 — 20 35 Southern Company Consolidated $ 423 $ 3,620 $ 4,400 $ 8,443 $ 8,273 $ 65 $ 13 $ 58 $ 365 (a) Represents the Southern Company parent entity. (b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. See Note 12 under " Southern Power " for additional information. Also excludes a $120 million continuing letter of credit facility entered into by Southern Power in December 2016 for standby letters of credit expiring in 2019. At December 31, 2016, the total amount available under the letter of credit facility was $82 million . (c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
Short-term borrowings	Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2016: Commercial paper $ 1,909 1.1 % Short-term bank debt 123 1.7 % Total $ 2,032 1.1 % December 31, 2015: Commercial paper $ 740 0.7 % Short-term bank debt 500 1.4 % Total $ 1,240 0.9 %
Alabama Power [Member]
Debt Disclosure [Line Items]
Credit arrangements with banks	At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Expires Within One Year 2017 2018 2020 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) $ 35 $ 500 $ 800 $ 1,335 $ 1,335 $ — $ 35
Southern Power [Member]
Debt Disclosure [Line Items]
Scheduled maturities and redemptions of securities due within one year	Maturities of long-term debt are as follows: December 31, 2016 (in millions) 2017 $ 561 2018 670 2019 600 2020 300 2021 300
Credit arrangements with banks	Project Construction Loan Facility Bridge Loan Facility Total Loan Facility Loan Facility Undrawn Letter of Credit Facility Letter of Credit Facility Undrawn (in millions) Roserock $ 63 $ 180 $ 243 $ 34 $ 23 $ 16
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: 2016 2015 (in millions) Senior notes $ 450 $ 700 Pollution control revenue bonds — 4 Capital leases 10 8 Total $ 460 $ 712
Short-term borrowings	Details of commercial paper borrowings outstanding were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) December 31, 2016 $ 392 1.1 % December 31, 2015 $ 158 0.6 %
Gulf Power [Member]
Debt Disclosure [Line Items]
Credit arrangements with banks	At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2017 2018 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $ 85 $ 195 $ 280 $ 280 $ 45 $ — $ 25 $ 60
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, 2016: Commercial paper $ 168 1.1% Short-term bank debt 100 1.5% Total $ 268 1.2% December 31, 2015: Commercial paper $ 142 0.7%
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, 2016 and 2015 was as follows: 2016 2015 (in millions) Parent company loans $ 551 $ — Senior notes 35 300 Bank term loans — 425 Pollution control revenue bonds (*) 40 — Capitalized leases 3 3 Outstanding at December 31 $ 629 $ 728 (*) Pollution control revenue bonds are classified as short term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028.
Credit arrangements with banks	At December 31, 2016 , committed credit arrangements with banks were as follows: Expires Executable Term Loans Expires Within One Year 2017 Total Unused One Year Two Years Term Out No Term Out (in millions) (in millions) (in millions) (in millions) $173 $173 $150 $— $13 $13 $160
Southern Company Gas [Member]
Debt Disclosure [Line Items]
Temporary Equity	The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below: Predecessor – (in millions) Balance at December 31, 2015 $ — Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest 46 Net income attributable to noncontrolling interest 14 Distribution to noncontrolling interest (19 ) Balance at June 30, 2016 $ 41 Successor – (in millions) Balance at July 1, 2016 $ 174 Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable (174 ) Balance at December 31, 2016 $ —
Credit arrangements with banks	At December 31, 2016 , committed credit arrangements with banks were as follows: Successor Expires Expires Within One Year Company 2017 2018 Total Unused Term Out No Term Out (in millions) (in millions) (in millions) Southern Company Gas Capital $ 49 $ 1,251 $ 1,300 $ 1,249 $ — $ 49 Nicor Gas 26 674 700 700 — 26 Total $ 75 $ 1,925 $ 2,000 $ 1,949 $ — $ 75
Short-term borrowings	Details of commercial paper borrowings outstanding were as follows: Commercial Paper at the End of the Period Amount Outstanding Weighted Average Interest Rate (in millions) Successor – December 31, 2016: Southern Company Gas Capital $ 733 1.09 % Nicor Gas 524 0.95 % Total $ 1,257 1.03 % Predecessor – December 31, 2015: Southern Company Gas Capital $ 471 0.71 % Nicor Gas 539 0.52 % Total $ 1,010 0.60 %
Redeemable Preferred Stock [Member] | Alabama Power [Member]
Debt Disclosure [Line Items]
Temporary Equity	Information for each outstanding series is in the table below: Preferred/Preference Stock Par Value/Stated Capital Per Share Shares Outstanding Redemption Price Per Share 4.92% Preferred Stock $100 80,000 $103.23 4.72% Preferred Stock $100 50,000 $102.18 4.64% Preferred Stock $100 60,000 $103.14 4.60% Preferred Stock $100 100,000 $104.20 4.52% Preferred Stock $100 50,000 $102.93 4.20% Preferred Stock $100 135,115 $105.00 5.83% Class A Preferred Stock $25 1,520,000 Stated Capital 6.45% Preference Stock $25 6,000,000 Stated Capital (*) 6.50% Preference Stock $25 2,000,000 Stated Capital (*) (*) Also includes a make-whole premium prior to October 1, 2017
Redeemable Preferred Stock [Member] | Mississippi Power [Member]
Debt Disclosure [Line Items]
Temporary Equity	Information for each outstanding series is in the table below: Preferred Stock Par Value/Stated Capital Per Share Shares Outstanding Redemption Price Per Share 4.40% Preferred Stock $ 100 8,867 $ 104.32 4.60% Preferred Stock $ 100 8,643 $ 107.00 4.72% Preferred Stock $ 100 16,700 $ 102.25 5.25% Preferred Stock (*) $ 100 300,000 $ 100.00

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments [Line Items]
Estimated minimum long-term purchase commitments	Estimated total obligations under these commitments at December 31, 2016 were as follows: Operating Leases (*) Other (in millions) 2017 $ 242 $ 8 2018 246 7 2019 249 6 2020 246 5 2021 249 5 2022 and thereafter 1,041 43 Total $ 2,273 $ 74 (*) A total of $197 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action.
Estimated minimum lease payments under operating leases	As of December 31, 2016 , estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2017 $ 31 $ 121 $ 152 2018 19 115 134 2019 10 103 113 2020 10 90 100 2021 8 82 90 2022 and thereafter 11 1,184 1,195 Total $ 89 $ 1,695 $ 1,784
Expected future contractual obligations	Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2016 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2017 $ 822 2018 602 2019 447 2020 394 2021 352 2022 and thereafter 2,591 Total $ 5,208
Alabama Power [Member]
Commitments [Line Items]
Estimated minimum long-term purchase commitments	Total estimated minimum long-term obligations at December 31, 2016 were as follows: Operating Lease PPAs (in millions) 2017 $ 40 2018 41 2019 43 2020 44 2021 46 2022 47 Total commitments $ 261
Estimated minimum lease payments under operating leases	As of December 31, 2016, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Vehicles & Other Total (in millions) 2017 $ 10 $ 4 $ 14 2018 7 3 10 2019 7 3 10 2020 6 2 8 2021 6 2 8 2022 and thereafter 9 1 10 Total $ 45 $ 15 $ 60
Georgia Power [Member]
Commitments [Line Items]
Estimated long-term obligations	Estimated total long-term obligations at December 31, 2016 were as follows: Affiliate Capital Leases Affiliate Operating Leases Non-Affiliate Operating Leases (c) Vogtle Units 1 and 2 Capacity Payments Total (in millions) 2017 $ 22 $ 72 $ 123 $ 8 $ 225 2018 22 63 126 7 218 2019 23 64 127 6 220 2020 23 65 123 5 216 2021 24 66 124 5 219 2022 and thereafter 204 479 882 43 1,608 Total $ 318 $ 809 $ 1,505 $ 74 $ 2,706 Less: amounts representing executory costs (a) 48 Net minimum lease payments 270 Less: amounts representing interest (b) 128 Present value of net minimum lease payments $ 142 (a) Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) a re estimated and included in total minimum lease payments. (b) Calculated using an adjusted incremental borrowing rate to reduce the present value of the net minimum lease payments to fair value. (c) A total of $197 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action.
Estimated minimum lease payments under operating leases	As of December 31, 2016, estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments Railcars Other Total (in millions) 2017 $ 12 $ 7 $ 19 2018 6 7 13 2019 3 6 9 2020 3 6 9 2021 2 6 8 2022 and thereafter 2 13 15 Total $ 28 $ 45 $ 73
Gulf Power [Member]
Commitments [Line Items]
Estimated minimum long-term purchase commitments	Estimated total minimum long-term commitments at December 31, 2016 were as follows: Operating Lease PPA (in millions) 2017 $ 79 2018 79 2019 79 2020 79 2021 79 2022 and thereafter 112 Total $ 507
Estimated minimum lease payments under operating leases	Estimated total minimum lease payments under these operating leases at December 31, 2016 were as follows: Minimum Lease Payments Barges & Railcars Other Total (in millions) 2017 $ 7 $ 1 $ 8 2018 5 1 6 2019 — 1 1 2020 — — — 2021 — — — 2022 and thereafter — 1 1 Total $ 12 $ 4 $ 16
Southern Company Gas [Member]
Commitments [Line Items]
Estimated minimum lease payments under operating leases	As of December 31, 2016 , the Company's estimated minimum lease payments under operating leases were as follows: Minimum Lease Payments (in millions) 2017 $ 18 2018 17 2019 16 2020 15 2021 15 2022 and thereafter 38 Total $ 119
Expected future contractual obligations	Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2016 were as follows: Pipeline Charges, Storage Capacity, and Gas Supply (in millions) 2017 $ 822 2018 602 2019 447 2020 394 2021 352 2022 and thereafter 2,591 Total $ 5,208

Common Stock and Stock Compen40

Common Stock and Stock Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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 Expected volatility 14.6% Expected term (in years) 5 Interest rate 1.5% Dividend yield 4.9% Weighted average grant-date fair value $2.20
Summary of stock option activity	Southern Company's activity in the stock option program for 2016 is summarized below: Shares Subject to Option Weighted Average Exercise Price Outstanding at December 31, 2015 35,749,906 $ 40.96 Exercised 11,120,613 40.26 Cancelled 43,429 41.38 Outstanding at December 31, 2016 24,585,864 $ 41.28 Exercisable at December 31, 2016 21,133,320 $ 41.26
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 2016 2015 2014 Expected volatility 15.0% 12.9% 12.6% Expected term (in years) 3 3 3 Interest rate 0.8% 1.0% 0.6% Annualized dividend rate (*) N/A N/A $2.03 Weighted average grant-date fair value $45.06 $46.38 $37.54 N/A - Not applicable (*) 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 EPS were as follows: Average Common Stock Shares 2016 2015 2014 (in millions) As reported shares 951 910 897 Effect of options and performance share award units 7 4 4 Diluted shares 958 914 901

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives (a)(b) $ 338 $ 333 $ — $ — $ 671 Interest rate derivatives — 14 — — 14 Nuclear decommissioning trusts: (c) Domestic equity 589 73 — — 662 Foreign equity 48 168 — — 216 U.S. Treasury and government agency securities — 92 — — 92 Municipal bonds — 73 — — 73 Corporate bonds 22 310 — — 332 Mortgage and asset backed securities — 183 — — 183 Private equity — — — 20 20 Other 11 15 — — 26 Cash equivalents 1,172 — — — 1,172 Other investments 9 — 1 — 10 Total $ 2,189 $ 1,261 $ 1 $ 20 $ 3,471 Liabilities: Energy-related derivatives (a)(b) $ 345 $ 285 $ — $ — $ 630 Interest rate derivatives — 29 — — 29 Foreign currency derivatives — 58 — — 58 Contingent consideration — — 18 — 18 Total $ 345 $ 372 $ 18 $ — $ 735 (a) Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives exclude cash collateral of $62 million . (c) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under " Nuclear Decommissioning " for additional information. 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.
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, 2016 and 2015 , 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, 2016 $ 20 $ 25 Not Applicable Not Applicable As of December 31, 2015 $ 17 $ 28 Not Applicable Not Applicable
Financial instruments not having carrying amount equal to fair value	As of December 31, 2016 and 2015 , 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: 2016 $ 45,080 $ 46,286 2015 $ 27,216 $ 27,913
Alabama Power [Member]
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total (in millions) Assets: Energy-related derivatives $ — $ 20 $ — $ — $ 20 Nuclear decommissioning trusts: (*) Domestic equity 385 72 — — 457 Foreign equity 48 47 — — 95 U.S. Treasury and government agency securities — 21 — — 21 Corporate bonds 22 146 — — 168 Mortgage and asset backed securities — 19 — — 19 Private equity — — — 20 20 Other — 10 — — 10 Cash equivalents 262 — — — 262 Total $ 717 $ 335 $ — $ 20 $ 1,072 Liabilities: Energy-related derivatives $ — $ 9 $ — $ — $ 9 (*) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. 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.
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, 2016 and 2015 , 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, 2016 $ 20 $ 25 Not Applicable Not Applicable As of December 31, 2015 $ 17 $ 28 Not Applicable Not Applicable
Financial instruments not having carrying amount equal to fair value	As of December 31, 2016 and 2015 , 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: 2016 $ 7,092 $ 7,544 2015 $ 6,849 $ 7,192
Georgia Power [Member]
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 44 $ — $ 44 Interest rate derivatives — 2 — 2 Nuclear decommissioning trusts: (*) Domestic equity 204 1 — 205 Foreign equity — 121 — 121 U.S. Treasury and government agency securities — 71 — 71 Municipal bonds — 73 — 73 Corporate bonds — 164 — 164 Mortgage and asset backed securities — 164 — 164 Other 11 5 — 16 Total $ 215 $ 645 $ — $ 860 Liabilities: Energy-related derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 3 — 3 Total $ — $ 11 $ — $ 11 (*) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. 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.
Financial instruments not having carrying amount equal to fair value	As of December 31, 2016 and 2015 , 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: 2016 $ 10,516 $ 11,034 2015 $ 10,145 $ 10,480
Gulf Power [Member]
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Cash equivalents $ 20 $ — $ — $ 20 Energy-related derivatives — 5 — 5 Total $ 20 $ 5 $ — $ 25 Liabilities: Energy-related derivatives $ — $ 29 $ — $ 29 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
Financial instruments not having carrying amount equal to fair value	As of December 31, 2016 and 2015 , 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: 2016 $ 1,074 $ 1,097 2015 $ 1,303 $ 1,339
Mississippi Power [Member]
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 3 $ — $ 3 Interest rate derivatives — 3 — 3 Cash equivalents 206 — — 206 Total $ 206 $ 6 $ — $ 212 Liabilities: Energy-related derivatives $ — $ 10 $ — $ 10 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
Financial instruments not having carrying amount equal to fair value	As of December 31, 2016 and 2015 , 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: 2016 $ 2,979 $ 2,922 2015 $ 2,537 $ 2,413
Southern Power [Member]
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives $ — $ 21 $ — $ 21 Interest rate derivatives — 1 — 1 Cash equivalents 628 — — 628 Total $ 628 $ 22 $ — $ 650 Liabilities: Energy-related derivatives $ — $ 5 $ — $ 5 Foreign currency derivatives — 58 — 58 Contingent consideration — — 18 18 Total $ — $ 63 $ 18 $ 81 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
Financial instruments not having carrying amount equal to fair value	As of December 31, 2016 and 2015 , 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: 2016 $ 5,628 $ 5,691 2015 $ 3,122 $ 3,117
Southern Company Gas [Member]
Fair Value Disclosures [Line Items]
Assets and liabilities measured at fair value on a recurring basis	As of December 31, 2016 , assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: Fair Value Measurements Using (a)(b) Successor – As of December 31, 2016 Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives $ 338 $ 239 $ — $ — $ 577 Liabilities: Energy-related derivatives $ 345 $ 224 $ — $ — $ 569 (a) Energy-related derivatives excludes $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $62 million . 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 (a)(b) Predecessor – As of December 31, 2015 Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient (NAV) Total (in millions) Assets: Energy-related derivatives $ 53 $ 113 $ — $ — $ 166 Interest rate derivatives — 9 — — 9 Total $ 53 $ 122 $ — $ — $ 175 Liabilities: Energy-related derivatives $ 63 $ 46 $ — $ — $ 109 (a) Energy-related derivatives excludes $10 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. (b) Energy-related derivatives excludes cash collateral of $96 million .
Financial instruments not having carrying amount equal to fair value	The following table presents the carrying amount and fair value of the Company's long-term debt as of December 31: Carrying Amount Fair Value (in millions) Long-term debt, including securities due within one year: Successor – As of December 31, 2016 $ 5,281 $ 5,491 Predecessor – As of December 31, 2015 $ 3,820 $ 4,066

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative [Line Items]
Notional amount of interest rate derivatives	At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Fair Value (in millions) (in millions) Cash Flow Hedges of Forecasted Debt $ 80 3-month LIBOR 2.32% December 2026 $ — Cash Flow Hedges of Existing Debt 900 1-month LIBOR 0.79% March 2018 3 Fair Value Hedges of Existing Debt 250 1.30% 3-month LIBOR + 0.17% August 2017 — 250 5.40% 3-month LIBOR + 4.02% June 2018 — 500 1.95% 3-month LIBOR + 0.76% December 2018 (2 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 1 300 2.75% 3-month LIBOR + 0.92% June 2020 1 1,500 2.35% 1-month LIBOR + 0.87% July 2021 (18 ) Derivatives not Designated as Hedges 47 (a,b) 3-month LIBOR 2.21% January 2017 (c) 1 Total $ 4,027 $ (14 ) (a) Swaption at RE Roserock LLC. See Note 12 for additional information. (b) Amortizing notional amount. (c) Represents the mandatory settlement date. Settlement amount was based on a 15 -year amortizing swap.
Schedule of foreign exchange contracts	At December 31, 2016 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ (34 ) 564 3.78% 500 1.85% June 2026 (24 ) Total $ 1,241 € 1,100 $ (58 )
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015 , the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 73 $ 27 $ 3 $ 130 Other deferred charges and assets/Other deferred credits and liabilities 25 33 — 87 Total derivatives designated as hedging instruments for regulatory purposes $ 98 $ 60 $ 3 $ 217 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 23 $ 7 $ 3 $ 2 Interest rate derivatives: Other current assets/Liabilities from risk management activities, net of collateral 12 1 19 23 Other deferred charges and assets/Other deferred credits and liabilities 1 28 — 7 Foreign currency derivatives: Other current assets/Liabilities from risk management activities, net of collateral — 25 — — Other deferred charges and assets/Other deferred credits and liabilities — 33 — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 36 $ 94 $ 22 $ 32 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Liabilities from risk management activities, net of collateral $ 489 $ 483 $ 1 $ 1 Other deferred charges and assets/Other deferred credits and liabilities 66 81 — — Interest rate derivatives: Other current assets/Liabilities from risk management activities, net of collateral 1 — 3 — Total derivatives not designated as hedging instruments $ 556 $ 564 $ 4 $ 1 Gross amounts recognized $ 690 $ 718 $ 29 $ 250 Gross amounts offset (a) $ (462 ) $ (524 ) $ (15 ) $ (15 ) Net amounts recognized in the Balance Sheets (b) $ 228 $ 194 $ 14 $ 235 (a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016 . (b) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.
Pre-tax effects on the balance sheets	At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (a) Other regulatory assets, current $ (16 ) $ (130 ) Other regulatory liabilities, current $ 56 $ 3 Other regulatory assets, deferred (19 ) (87 ) Other regulatory liabilities, deferred 12 — Total energy-related derivative gains (losses) (b) $ (35 ) $ (217 ) $ 68 $ 3 (a) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet. (b) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million as of December 31, 2016 .
Pre-tax effects on the statements of income	For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Amount Derivative Category 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Energy-related derivatives $ 18 $ — $ — Depreciation and amortization $ 2 $ — $ — Cost of natural gas (1 ) — — Interest rate derivatives (180 ) (22 ) (16 ) Interest expense, net of amounts capitalized (18 ) (9 ) (8 ) Foreign currency derivatives (58 ) — — Interest expense, net of amounts capitalized (13 ) — — Other income (expense), net (*) (82 ) — — Total $ (220 ) $ (22 ) $ (16 ) $ (112 ) $ (9 ) $ (8 ) (*) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
Pre-tax effect of interest rate and energy related derivatives	For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows: Derivatives in Fair Value Hedging Relationships Gain (Loss) Derivative Category Statements of Income Location 2016 2015 2014 (in millions) Interest rate derivatives: Interest expense, net of amounts capitalized $ (21 ) $ 2 $ (3 )
Pre-tax effect of interest rate and energy related derivatives	For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: Derivatives Not Designated as Hedging Instruments Unrealized Gain (Loss) Recognized in Income Amount Derivative Category Statements of Income Location 2016 2015 2014 (in millions) Energy-related derivatives Wholesale electric revenues $ 2 $ (5 ) $ 6 Fuel — 3 (4 ) Natural gas revenues (*) 33 — — Cost of natural gas 3 — — Total $ 38 $ (2 ) $ 2 (*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the period ended December 31, 2016 .
Alabama Power [Member]
Derivative [Line Items]
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected on the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 13 $ 5 $ 1 $ 40 Other deferred charges and assets/Other deferred credits and liabilities 7 4 — 15 Total derivatives designated as hedging instruments for regulatory purposes $ 20 $ 9 $ 1 $ 55 Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets/Other current liabilities $ — $ — $ — $ 15 Gross amounts recognized $ 20 $ 9 $ 1 $ 70 Gross amounts offset $ (8 ) $ (8 ) $ (1 ) $ (1 ) Net amounts recognized in the Balance Sheets (*) $ 12 $ 1 $ — $ 69 (*) At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.
Pre-tax effects on the balance sheets	At December 31, 2016 and 2015 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (1 ) $ (40 ) Other current liabilities $ 8 $ 1 Other regulatory assets, deferred — (15 ) Other regulatory liabilities, deferred 4 — Total energy-related derivative gains (losses) $ (1 ) $ (55 ) $ 12 $ 1 (*) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.
Pre-tax effects on the statements of income	For the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Interest rate derivatives $ (3 ) $ (7 ) $ (8 ) Interest expense, net of amounts capitalized $ (6 ) $ (3 ) $ (3 )
Georgia Power [Member]
Derivative [Line Items]
Notional amount of interest rate derivatives	At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Fair Value Hedges of Existing Debt $ 250 5.40% 3-month LIBOR + 4.02% June 2018 $ — 500 1.95% 3-month LIBOR + 0.76% December 2018 (2 ) 200 4.25% 3-month LIBOR + 2.46% December 2019 1 Total $ 950 $ (1 )
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 30 $ 1 $ 2 $ 12 Other deferred charges and assets/Other deferred credits and liabilities 14 7 — 3 Total derivatives designated as hedging instruments for regulatory purposes $ 44 $ 8 $ 2 $ 15 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ 2 $ — $ 5 $ — Other deferred charges and assets/Other deferred credits and liabilities — 3 — 6 Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 2 $ 3 $ 5 $ 6 Gross amounts recognized $ 46 $ 11 $ 7 $ 21 Gross amounts offset $ (8 ) $ (8 ) $ (6 ) $ (6 ) Net amounts recognized in the Balance Sheets (*) $ 38 $ 3 $ 1 $ 15 (*) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.
Pre-tax effects on the balance sheets	At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ — $ (12 ) Other regulatory liabilities, current $ 29 $ 2 Other regulatory assets, deferred — (3 ) Other deferred credits and liabilities 7 — Total energy-related derivative gains (losses) $ — $ (15 ) $ 36 $ 2 (*) At December 31, 2016 , the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented gross on the balance sheet.
Pre-tax effects on the statements of income	For the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Interest rate derivatives $ — $ (15 ) $ (8 ) Interest expense, net of amounts capitalized $ (4 ) $ (3 ) $ (3 )
Gulf Power [Member]
Derivative [Line Items]
Notional amount of interest rate derivatives	At December 31, 2016 , 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 $ —
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Liabilities from risk management activities $ 4 $ 12 $ — $ 49 Other deferred charges and assets/Other deferred credits and liabilities 1 17 — 51 Total derivatives designated as hedging instruments for regulatory purposes $ 5 $ 29 $ — $ 100 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Liabilities from risk management activities — — 1 — Gross amounts recognized $ 5 $ 29 $ 1 $ 100 Gross amounts offset $ (4 ) $ (4 ) $ — $ — Net amounts recognized in the Balance Sheets (*) $ 1 $ 25 $ 1 $ 100 (*) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.
Pre-tax effects on the balance sheets	At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (9 ) $ (49 ) Other regulatory liabilities, current $ 1 $ — Other regulatory assets, deferred (16 ) (51 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (25 ) $ (100 ) $ 1 $ —
Pre-tax effects on the statements of income	For the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Interest rate derivatives $ — $ 1 $ — Interest expense, net of amounts capitalized $ (1 ) $ (1 ) $ (1 )
Mississippi Power [Member]
Derivative [Line Items]
Notional amount of interest rate derivatives	At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 900 1-month LIBOR 0.79% March 2018 $ 3
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected on the balance sheets as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 2 $ 6 $ — $ 29 Other deferred charges and assets/Other deferred credits and liabilities 2 5 — 18 Total derivatives designated as hedging instruments for regulatory purposes $ 4 $ 11 $ — $ 47 Derivatives designated as hedging instruments in cash flow and fair value hedges Interest rate derivatives: Other current assets/Other current liabilities $ 2 $ — $ — $ — Other deferred charges and assets/Other deferred credits and liabilities 1 — — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 3 $ — $ — $ — Gross amounts recognized $ 7 $ 11 $ — $ 47 Gross amounts offset $ (3 ) $ (3 ) $ — $ — Net amounts recognized in the Balance Sheets (*) $ 4 $ 8 $ — $ 47 (*) At December 31, 2015 , the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.
Pre-tax effects on the balance sheets	At December 31, 2016 and 2015 , the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015 (in millions) (in millions) Energy-related derivatives: (*) Other regulatory assets, current $ (5 ) $ (29 ) Other regulatory liabilities, current $ 1 $ — Other regulatory assets, deferred (3 ) (18 ) Other regulatory liabilities, deferred — — Total energy-related derivative gains (losses) $ (8 ) $ (47 ) $ 1 $ — (*) At December 31, 2016 , the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015 , the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.
Pre-tax effects on the statements of income	For the year ended December 31, 2016, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were $3 million . For the years ended December 31, 2015 and 2014, these effects were immaterial.
Southern Power [Member]
Derivative [Line Items]
Notional amount of interest rate derivatives	At December 31, 2016 , the following interest rate derivatives were outstanding: Notional Interest Weighted Average Interest Hedge Fair Value (in millions) (in millions) Derivatives not Designated as Hedges $ 47 (a.b) 3-month LIBOR 2.21% January 2017 (c) $ 1 (a) Swaption at RE Roserock LLC. (b) Amortizing notional amount. (c) Represents the mandatory settlement date. Settlement amount was based on a 15 -year amortizing swap.
Schedule of foreign exchange contracts	At December 31, 2016 , the following foreign currency derivatives were outstanding: Pay Notional Pay Rate Receive Notional Receive Rate Hedge Fair Value (in millions) (in millions) (in millions) Cash Flow Hedges of Existing Debt $ 677 2.95% € 600 1.00% June 2022 $ (34 ) 564 3.78% 500 1.85% June 2026 (24 ) Total $ 1,241 € 1,100 $ (58 )
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015, the fair value of energy-related, interest rate, and foreign currency derivatives reflected in the consolidated balance sheets is as follows: 2016 2015 Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities (in millions) Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Other current assets/Other current liabilities $ 18 $ 4 $ 3 $ 2 Foreign currency derivatives: Other current assets/Other current liabilities — 25 — — Other deferred charges and assets/Other deferred credits and liabilities — 33 — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 18 $ 62 $ 3 $ 2 Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets/Other current liabilities $ 3 $ 1 $ 1 $ 1 Interest rate derivatives: Other current assets/Other current liabilities 1 — 3 — Total derivatives not designated as hedging instruments $ 4 $ 1 $ 4 $ 1 Gross amounts of recognized assets and liabilities $ 22 $ 63 $ 7 $ 3 Gross amounts offset $ (5 ) $ (5 ) $ (1 ) $ (1 ) Net amounts of assets and liabilities (*) $ 17 $ 58 $ 6 $ 2 (*) At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the consolidated balance sheet.
Pre-tax effects on the statements of income	For the years ended December 31, 2016 , 2015 , and 2014 , the pre-tax effects of energy-related, interest rate, and foreign currency derivatives designated as cash flow hedging instruments on the consolidated statements of income were as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivative Category 2016 2015 2014 Statements of Income Location 2016 2015 2014 (in millions) (in millions) Energy-related derivatives $ 14 $ — $ — Amortization $ 2 $ — $ — Interest rate derivatives — — — Interest expense, net of amounts capitalized (1 ) (1 ) (1 ) Foreign currency derivatives (58 ) — — Interest expense, net of amounts capitalized (13 ) — — Other income (expense), net (82 ) — — Total $ (44 ) $ — $ — $ (94 ) $ (1 ) $ (1 )
Southern Company Gas [Member]
Derivative [Line Items]
Fair value of energy-related derivatives and interest rate derivatives	At December 31, 2016 and 2015 , the fair value of energy-related derivatives and interest rate derivatives was reflected in the consolidated balance sheets as follows: Asset Derivatives Liability Derivatives Successor Predecessor Successor Predecessor Derivative Category Balance Sheet Location December 31, 2016 December 31, 2015 Balance Sheet Location December 31, 2016 December 31, 2015 (in millions) (in millions) (in millions) (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Assets from risk management activities – current $ 24 $ 10 Liabilities from risk management activities – current $ 3 $ 28 Other deferred charges and assets 1 — Other deferred credits and liabilities — 2 Total derivatives designated as hedging instruments for regulatory purposes $ 25 $ 10 $ 3 $ 30 Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities – current $ 4 $ 3 Liabilities from risk management activities – current $ 3 $ 5 Other deferred charges and assets — — Other deferred credits and liabilities — 2 Interest rate derivatives: Assets from risk management activities – current — 9 Liabilities from risk management activities – current — — Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 4 $ 12 $ 3 $ 7 Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities – current $ 486 $ 741 Liabilities from risk management activities – current $ 482 $ 644 Other deferred charges and assets 66 179 Other deferred credits and liabilities 81 185 Total derivatives not designated as hedging instruments $ 552 $ 920 $ 563 $ 829 Gross amounts of recognized assets and liabilities (a)(b) $ 581 $ 942 $ 569 $ 866 Gross amounts offset in the Balance Sheet $ (435 ) $ (724 ) $ (497 ) $ (820 ) Net amounts of derivatives assets and liabilities, presented in the Balance Sheet (c) $ 146 $ 218 $ 72 $ 46 (a) The gross amounts of recognized assets and liabilities are netted on the balance sheets to the extent that there were netting arrangements with the counterparties. (b) The gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $62 million as of December 31, 2016 and $96 million as of December 31, 2015 . (c) As of December 31, 2016 and 2015, letters of credit from counterparties offset an immaterial portion of these assets under master netting arrangements.
Pre-tax effects on the balance sheets	At December 31, 2016 and 2015 , the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows: Unrealized Losses Unrealized Gains Successor Predecessor Successor Predecessor Derivative Category Balance Sheet Location December 31, 2016 December 31, 2015 Balance Sheet Location December 31, 2016 December 31, 2015 (in millions) (in millions) (in millions) (in millions) Energy-related derivatives: Other regulatory assets, current $ (1 ) $ (15 ) Other regulatory liabilities, current $ 17 $ 15 Other regulatory assets, deferred — (2 ) Other regulatory liabilities, deferred 1 — Total energy-related derivative gains (losses) (*) $ (1 ) $ (17 ) $ 18 $ 15 (*) Fair value gains and losses included in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million as of December 31, 2016 and $19 million as of December 31, 2015 .
Pre-tax effects on the statements of income	For the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were as follows: Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Successor Predecessor Successor Predecessor Derivatives in Cash Flow Hedging Relationships July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 Statements of Income Location July 1, 2016 through December 31, 2016 January 1, 2016 through June 30, 2016 (in millions) (in millions) (in millions) (in millions) Energy-related derivatives $ 2 $ — Cost of natural gas $ (1 ) $ (1 ) Interest rate derivatives (5 ) (64 ) Interest expense, net of amounts capitalized — — Total derivatives in cash flow $ (3 ) $ (64 ) $ (1 ) $ (1 ) Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Predecessor Predecessor Derivatives in Cash Flow Hedging Relationships 2015 2014 Statements of Income Location 2015 2014 (in millions) (in millions) Energy-related derivatives $ 3 $ (8 ) Cost of natural gas $ (10 ) $ 4 Other operations and maintenance (1 ) 1 Interest rate derivatives — — Interest expense, net of amounts capitalized 2 — Total derivatives in cash flow $ 3 $ (8 ) $ (9 ) $ 5
Pre-tax effect of interest rate and energy related derivatives	For the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows: Gain (Loss) Successor Predecessor July 1, 2016 through December 31, January 1, 2016 through June 30, Years Ended December 31, Derivatives in Non-Designated Hedging Relationships Statements of Income Location 2016 2016 2015 2014 (in millions) (in millions) Energy-related derivatives Natural gas revenues (*) $ 33 $ (1 ) $ 56 $ 149 Cost of natural gas 3 (62 ) (6 ) (7 ) Total derivatives in non-designated hedging relationships $ 36 $ (63 ) $ 50 $ 142 (*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $6 million for the successor periods of July 1, 2016 through December 31, 2016 and $3 million , $12 million , and $(7) million for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 , respectively.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition	The following table presents Southern Power's acquisitions for the year ended December 31, 2015 . During the year ended December 31, 2016 , the fair values of assets and liabilities acquired for all projects listed below were finalized with no changes to amounts originally reported. Project Facility Resource Seller; Acquisition Date Approximate MW ) Location Southern Power Percentage Ownership Actual COD PPA Acquisitions for the Year Ended December 31, 2015 Desert Stateline Solar First Solar Inc. 299 (a) San Bernardino County, CA 51 % (b) From December 2015 to July 2016 20 years Garland and Garland A Solar Recurrent Energy, LLC 205 Kern County, CA 51 % (b) October and August 2016 15 years and 20 years Kay Wind Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 2015 20 years Lost Hills Blackwell Solar First Solar Inc. 33 Kern County, CA 51 % (b) April 2015 29 years Morelos Solar Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % (c) November 2015 20 years North Star Solar First Solar Inc. 61 Fresno County, CA 51 % (b) June 2015 20 years Roserock Solar Recurrent Energy, LLC November 23, 2015 160 Pecos County, TX 51 % (b) November 2016 20 years Tranquillity Solar Recurrent Energy, LLC 205 Fresno County, CA 51 % (b) July 2016 18 years (a) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (b) 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. (c) Southern Power owns 90% , with the minority owner, TRE, owning 10% . The following table presents Southern Power's acquisitions during and subsequent to the year ended December 31, 2016 . Project Facility Resource Seller; Acquisition Date Approximate Nameplate Capacity (MW) Location Southern Power Percentage Ownership Actual/Expected COD PPA Contract Period Acquisitions During the Year Ended December 31, 2016 Boulder 1 Solar SunPower Corp. 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC 20 Imperial County, CA 90 % (b) February 2016 20 years East Pecos Solar First Solar, Inc. 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower Corp. 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc. 102 Dawson County, TX 100 % Second quarter 2017 15 years Mankato (d) Natural Gas Calpine Corporation October 26, 2016 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC 74 Rutherford County, NC 90 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc. 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc. 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy Wind Global LLC 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years Acquisitions Subsequent to December 31, 2016 Bethel Wind Invenergy Wind Global LLC 276 Castro County, TX 100 % January 2017 12 years (a) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) Southern Power owns 90% , with the minority owner, Turner Renewable Energy, LLC (TRE), owning 10% . (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) Southern Power owns 90.1% , with the minority owner, Invenergy Wind Global LLC, owning 9.9% . The allocation of the purchase price is as follows: PowerSecure Purchase Price December 31, 2016 (in millions) Current assets $ 172 Property, plant, and equipment 46 Intangible assets 101 Goodwill 282 Other assets 4 Current liabilities (114 ) Long-term debt, including current portion (48 ) Deferred credits and other liabilities (14 ) Total purchase price $ 429 The following table presents the purchase price allocation: Southern Company Gas Purchase Price December 31, 2016 (in millions) Current assets $ 1,557 Property, plant, and equipment 10,108 Goodwill 5,967 Intangible assets 400 Regulatory assets 1,118 Other assets 229 Current liabilities (2,201 ) Other liabilities (4,742 ) Long-term debt (4,261 ) Noncontrolling interests (174 ) Total purchase price $ 8,001 The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: Southern Power (b)(c) $ 2,345 Noncontrolling interests (d)(e) 258 Total purchase price $ 2,603 (a) Intangible assets consist of acquired PPAs that will be amortized over 10 and 20 -year terms. The estimated amortization for future periods is approximately $9 million per year. (b) At December 31, 2016 , $461 million is included in acquisitions payable on the balance sheets. (c) Includes approximately $281 million of contingent consideration, of which $67 million remains payable at December 31, 2016. (d) Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. (e) Includes approximately $142 million of contingent consideration The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2015 (in millions) CWIP $ 1,367 Property, plant, and equipment 315 Intangible assets (a) 274 Other assets 64 Accounts payable (89 ) Total purchase price $ 1,931 Funded by: Southern Power (b) $ 1,440 Noncontrolling interests (c) (d) 491 Total purchase price $ 1,931 (a) Intangible assets consist of acquired PPAs that will be amortized over 20 -year terms. The estimated amortization for future periods is approximately $14 million per year. (b) Includes approximately $195 million of contingent consideration, all of which has been paid at December 31, 2016 . (c) Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. (d) Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.
Business Acquisition, Pro Forma Information [Table Text Block]	The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger. 2016 2015 Operating revenues (in millions) $ 21,791 $ 21,430 Net income attributable to Southern Company (in millions) $ 2,591 $ 2,665 Basic EPS $ 2.70 $ 2.85 Diluted EPS $ 2.68 $ 2.84
Schedule of Construction Projects	During 2016, in accordance with Southern Power's overall growth strategy, Southern Power completed construction of, and placed in service, the projects set forth in the table below. Total costs of construction incurred for these projects were $3.2 billion . Solar Facility Seller Approximate Nameplate Capacity ( MW ) Location Actual COD PPA Contract Period Butler CERSM, LLC and Community Energy, Inc. 103 Taylor County, GA December 2016 30 years (a) Butler Solar Farm Strata Solar Development, LLC 22 Taylor County, GA February 2016 20 years (a) Desert Stateline First Solar Development, LLC 299 (b) San Bernardino County, CA From December 2015 to July 2016 20 years Garland Recurrent Energy, LLC 185 Kern County, CA October 2016 15 years Garland A Recurrent Energy, LLC 20 Kern County, CA August 2016 20 years Pawpaw Longview Solar, LLC 30 Taylor County, GA March 2016 30 years Roserock (c) Recurrent Energy, LLC 160 Pecos County, TX November 2016 20 years Sandhills N/A 146 Taylor County, GA October 2016 25 years Tranquillity Recurrent Energy, LLC 205 Fresno County, CA July 2016 18 years (a) Affiliate PPA approved by the FERC. (b) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (c) Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. The following table presents Southern Power's construction projects in progress as of December 31, 2016: Project Facility Resource Approximate Nameplate Capacity (MW) Location Actual/Expected COD PPA Contract Period East Pecos Solar 120 Pecos County, TX March 2017 15 years Lamesa Solar 102 Dawson County, TX Second quarter 2017 15 years Mankato Natural Gas 345 Mankato, MN Second quarter 2019 20 years
Southern Company Gas [Member]
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition	The following table presents the final purchase price allocation: Successor Predecessor New Basis Old Basis Change in Basis (in millions) (in millions) Current assets $ 1,557 $ 1,474 $ 83 Property, plant, and equipment 10,108 10,148 (40 ) Goodwill 5,967 1,813 4,154 Other intangible assets 400 101 299 Regulatory assets 1,118 679 439 Other assets 229 273 (44 ) Current liabilities (2,201 ) (2,205 ) 4 Other liabilities (4,742 ) (4,600 ) (142 ) Long-term debt (4,261 ) (3,709 ) (552 ) Contingently redeemable noncontrolling interest (174 ) (41 ) (133 ) Total purchase price/equity $ 8,001 $ 3,933 $ 4,068
Southern Power [Member]
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition	The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2015 (in millions) CWIP $ 1,367 Property, plant, and equipment 315 Intangible assets (a) 274 Other assets 64 Accounts payable (89 ) Total purchase price $ 1,931 Funded by: The Company (b) $ 1,440 Noncontrolling interests (c) (d) 491 Total purchase price $ 1,931 (a) Intangible assets consist of acquired PPAs that will be amortized over 20 -year terms. The estimated amortization for future periods is approximately $14 million per year. See Note 1 under "Impairment of Long-Lived Assets and Intangibles" for additional information. (b) Includes approximately $195 million of contingent consideration, all of which had been paid at December 31, 2016 . (c) Includes approximately $227 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity. (d) Includes approximately $76 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: 2016 (in millions) CWIP $ 2,354 Property, plant, and equipment 302 Intangible assets (a) 128 Other assets 52 Accounts payable (16 ) Debt (217 ) Total purchase price $ 2,603 Funded by: The Company (b) (c) $ 2,345 Noncontrolling interests (d) (e) 258 Total purchase price $ 2,603 The following table presents the Company's acquisitions during and subsequent to the year ended December 31, 2016. Project Facility Resource Seller; Acquisition Date Approximate Nameplate Capacity ( MW ) Location Percentage Ownership Actual/Expected COD PPA Contract Period Acquisitions During the Year Ended December 31, 2016 Boulder 1 Solar SunPower 100 Clark County, NV 51 % (a) December 2016 20 years Calipatria Solar Solar Frontier Americas Holding LLC 20 Imperial County, CA 90 % (b) February 2016 20 years East Pecos Solar First Solar, Inc. 120 Pecos County, TX 100 % March 2017 15 years Grant Plains Wind Apex Clean Energy Holdings, LLC 147 Grant County, OK 100 % December 2016 20 years and 12 years (c) Grant Wind Wind Apex Clean Energy Holdings, LLC 151 Grant County, OK 100 % April 2016 20 years Henrietta Solar SunPower 102 Kings County, CA 51 % (a) July 2016 20 years Lamesa Solar RES America Developments Inc. 102 Dawson County, TX 100 % Second quarter 2017 15 years Mankato (d) Natural Gas Calpine Corporation October 26, 2016 375 Mankato, MN 100 % N/A (e) 10 years Passadumkeag Wind Quantum Utility Generation, LLC 42 Penobscot County, ME 100 % July 2016 15 years Rutherford Solar Cypress Creek Renewables, LLC 74 Rutherford County, NC 90 % (b) December 2016 15 years Salt Fork Wind EDF Renewable Energy, Inc. 174 Donley and Gray Counties, TX 100 % December 2016 14 years and 12 years Tyler Bluff Wind EDF Renewable Energy, Inc. 125 Cooke County, TX 100 % December 2016 12 years Wake Wind Wind Invenergy 257 Floyd and Crosby Counties, TX 90.1 % (f) October 2016 12 years Acquisitions Subsequent to December 31, 2016 Bethel Wind Invenergy 276 Castro County, TX 100 % January 2017 12 years (a) The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49% , respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. (b) The Company owns 90% , with the minority owner, TRE, owning 10% . (c) In addition to the 20 -year and 12 -year PPAs, the facility has a 10 -year contract with Allianz Risk Transfer (Bermuda) Ltd. (d) Under the terms of the remaining 10 -year PPA and the 20 -year expansion PPA, approximately $408 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2016. (e) The acquisition included a fully operational 375 -MW natural gas-fired combined-cycle facility. (f) The Company owns 90.1% , with the minority owner, Invenergy, owning 9.9% . The following table presents the Company's acquisitions for the year ended December 31, 2015 . During the year ended December 31, 2016 , the fair values of assets and liabilities acquired for all projects listed below were finalized with no changes to amounts originally reported. Project Facility Resource Seller; Acquisition Date Approximate MW ) Location Percentage Ownership Actual COD PPA Acquisitions for the Year Ended December 31, 2015 Desert Stateline Solar First Solar 299 (a) San Bernardino County, CA 51 % (b) From December 2015 to July 2016 20 years Garland and Garland A Solar Recurrent 205 Kern County, CA 51 % (b) October and August 2016 15 years and 20 years Kay Wind Wind Apex Clean Energy Holdings, LLC December 11, 2015 299 Kay County, OK 100 % December 2015 20 years Lost Hills Blackwell Solar First Solar 33 Kern County, CA 51 % (b) April 2015 29 years Morelos Solar Solar Frontier Americas Holding, LLC 15 Kern County, CA 90 % (c) November 2015 20 years North Star Solar First Solar 61 Fresno County, CA 51 % (b) June 2015 20 years Roserock Solar Recurrent November 23, 2015 160 Pecos County, TX 51 % (b) November 2016 20 years Tranquillity Solar Recurrent 205 Fresno County, CA 51 % (b) July 2016 18 years (a) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (b) 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. (c) The Company owns 90% , with the minority owner, TRE, owning 10% .
Business Acquisition, Pro Forma Information [Table Text Block]	The solar and wind acquisitions did not have operating revenues or net income prior to the completion of construction and the generating facility being placed in service; therefore, supplemental pro forma information as if these acquisitions occurred as of the beginning of 2016 , and for the comparable 2015 year, is not meaningful and has been omitted. However, the Mankato acquisition is an operating facility and unaudited supplemental pro forma information, as though the acquisition occurred as of the beginning of 2016 and for the comparable 2015 year, is as follows: 2016 2015 (in millions) Revenues $ 40 $ 39 Net income $ 14 $ 11
Schedule of Construction Projects	The following table presents the Company's construction projects in progress as of December 31, 2016: Project Facility Resource Approximate Nameplate Capacity ( MW ) Location Actual/Expected COD PPA Contract Period East Pecos Solar 120 Pecos County, TX March 2017 15 years Lamesa Solar 102 Dawson County, TX Second quarter 2017 15 years Mankato Natural Gas 345 Mankato, MN Second quarter 2019 20 years During 2016 , in accordance with its overall growth strategy, the Company completed construction of, and placed in service, the projects set forth in the table below. Total costs of construction incurred for these projects were $3.2 billion . Solar Facility Seller Approximate Nameplate Capacity ( MW ) Location Actual COD PPA Contract Period Butler CERSM, LLC and Community Energy, Inc. 103 Taylor County, GA December 2016 30 years (a) Butler Solar Farm Strata Solar Development, LLC 22 Taylor County, GA February 2016 20 years (a) Desert Stateline First Solar Development, LLC 299 (b) San Bernardino County, CA From December 2015 to July 2016 20 years Garland Recurrent 185 Kern County, CA October 2016 15 years Garland A Recurrent 20 Kern County, CA August 2016 20 years Pawpaw Longview Solar, LLC 30 Taylor County, GA March 2016 30 years Roserock (c) Recurrent 160 Pecos County, TX November 2016 20 years Sandhills N/A 146 Taylor County, GA October 2016 25 years Tranquillity Recurrent 205 Fresno County, CA July 2016 18 years (a) Affiliate PPA approved by the FERC. (b) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and the remainder by July 2016. (c) Prior to placing the Roserock facility in service, certain solar panels were damaged. While the facility is currently generating energy as expected, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels.

Segment and Related Informati44

Segment and Related Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting Information [Line Items]
Financial data for business segments	Financial data for business segments and products and services for the years ended December 31, 2016 , 2015 , and 2014 was as follows: Electric Utilities Traditional Electric Operating Companies Southern Power Eliminations Total Southern Company Gas All Other Eliminations Consolidated (in millions) 2016 Operating revenues $ 16,803 $ 1,577 $ (439 ) $ 17,941 $ 1,652 $ 463 $ (160 ) $ 19,896 Depreciation and amortization 1,881 352 — 2,233 238 31 — 2,502 Interest income 6 7 — 13 2 20 (15 ) 20 Earnings from equity method investments 2 — — 2 60 (3 ) — 59 Interest expense 814 117 — 931 81 317 (12 ) 1,317 Income taxes 1,286 (195 ) — 1,091 76 (216 ) — 951 Segment net income (loss) (a) (b) 2,233 338 — 2,571 114 (230 ) (7 ) 2,448 Total assets 72,141 15,169 (316 ) 86,994 21,853 2,474 (1,624 ) 109,697 Gross property additions 4,852 2,114 — 6,966 618 41 (1 ) 7,624 2015 Operating revenues $ 16,491 $ 1,390 $ (439 ) $ 17,442 $ — $ 152 $ (105 ) $ 17,489 Depreciation and amortization 1,772 248 — 2,020 — 14 — 2,034 Interest income 19 2 1 22 — 6 (5 ) 23 Earnings from equity method investments 1 — — 1 — (1 ) — — Interest expense 697 77 — 774 — 69 (3 ) 840 Income taxes 1,305 21 — 1,326 — (132 ) — 1,194 Segment net income (loss) (a) (b) 2,186 215 — 2,401 — (32 ) (2 ) 2,367 Total assets 69,052 8,905 (397 ) 77,560 — 1,819 (1,061 ) 78,318 Gross property additions 5,124 1,005 — 6,129 — 40 — 6,169 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 Earnings from equity method investments 1 — — 1 — (1 ) — — 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 (a) Attributable to Southern Company. (b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $428 million ( $264 million after tax) in 2016, $365 million ( $226 million after tax) in 2015, and $868 million ( $536 million after tax) in 2014. See Note 3 under " Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate " for additional information. (c) Net of $202 million of unamortized debt issuance costs as of December 31, 2014. Also net of $488 million of deferred tax assets as of December 31, 2014.
Financial data for products and services	Products and Services Electric Utilities' Revenues Year Retail Wholesale Other Total (in millions) 2016 $ 15,234 $ 1,926 $ 781 $ 17,941 2015 14,987 1,798 657 17,442 2014 15,550 2,184 672 18,406 Southern Company Gas' Revenues Year Gas Gas All Other Total (in millions) 2016 $ 1,266 $ 354 $ 32 $ 1,652
Southern Company Gas [Member]
Segment Reporting Information [Line Items]
Financial data for business segments	Financial data for business segments for the successor period of July 1, 2016 through December 31, 2016 and for the predecessor periods of January 1, 2016 through June 30, 2016 and the years ended December 31, 2015 and 2014 were as follows: Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (*) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Successor – July 1, 2016 through December 31, 2016 Operating revenues $ 1,342 $ 354 $ 24 $ 31 $ 1,751 $ 3 $ (102 ) $ 1,652 Depreciation and 185 35 1 9 230 8 — 238 Earnings from equity — — — 58 58 2 — 60 Interest expense (105 ) (1 ) (3 ) (16 ) (125 ) 44 — (81 ) Income taxes 51 7 (3 ) 16 71 5 — 76 Segment net income 77 19 — 20 116 (2 ) — 114 Gross property 561 5 1 54 621 11 — 632 Successor – Total 19,453 2,084 1,127 2,211 24,875 11,145 (14,167 ) 21,853 (*) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. Gas Distribution Operations Gas Marketing Services Wholesale Gas Services (*) Gas Midstream Operations Total All Other Eliminations Consolidated (in millions) Predecessor – January 1, 2016 through June 30, 2016 Operating revenues $ 1,575 $ 435 $ (32 ) $ 25 $ 2,003 $ 4 $ (102 ) $ 1,905 Depreciation and 178 11 1 9 199 7 — 206 EBIT 353 109 (68 ) (6 ) 388 (60 ) — 328 Gross property additions 484 4 1 43 532 16 — 548 Predecessor – Year Ended December 31, 2015 Operating revenues $ 3,049 $ 835 $ 202 $ 55 $ 4,141 $ 11 $ (211 ) $ 3,941 Depreciation and 336 25 1 18 380 17 — 397 EBIT 581 152 110 (23 ) 820 (59 ) — 761 Gross property additions 957 7 2 27 993 34 — 1,027 Predecessor – Total 12,519 686 935 692 14,832 9,662 (9,740 ) 14,754 Predecessor – Year Ended December 31, 2014 Operating revenues $ 4,001 $ 994 $ 578 $ 88 5,661 $ 7 $ (283 ) $ 5,385 Depreciation and 317 28 1 18 364 16 — 380 EBIT 582 132 425 (17 ) 1,122 (10 ) — 1,112 Gross property additions 715 11 2 15 743 26 — 769 Predecessor – Total 12,038 670 1,402 694 14,804 9,705 (9,647 ) 14,862 (*) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. Third Party Gross Revenues Intercompany Revenues Total Gross Revenues Less Gross Gas Costs Operating Revenues (in millions) Successor – July 1, 2016 through $ 5,807 $ 333 $ 6,140 $ 6,116 $ 24 (in millions) Predecessor – January 1, 2016 through $ 2,500 $ 143 $ 2,643 $ 2,675 $ (32 ) Year Ended December 31, 2015 6,286 408 6,694 6,492 202 Year Ended December 31, 2014 10,709 718 11,427 10,849 578

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2016
Southern Company Gas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Schedule of Disposal Groups, Including Discontinued Operations	The components of discontinued operations recorded on the statements of income for the predecessor year ended December 31, 2014 are as follows: Year Ended December 31, 2014 (in millions) Operating revenues $ 243 Operating expenses Cost of goods sold 149 Operation and maintenance 75 Depreciation and amortization 5 Taxes other than income taxes 5 Loss on sale and goodwill impairment (*) 28 Total operating expenses 262 Operating (loss) income (19 ) (Loss) income before income taxes (19 ) Income tax expense (61 ) (Loss) income from discontinued operations, net of tax $ (80 ) (*) Primarily reflects $7 million due to the suspension of depreciation and amortization during 2014 and $19 million of goodwill attributable to Tropical Shipping that was impaired in 2014, based on the negotiated sales price.

Noncontrolling Interest (Tables

Noncontrolling Interest (Tables) - Southern Power [Member]	12 Months Ended
	Dec. 31, 2016
Noncontrolling Interest [Line Items]
Redeemable Noncontrolling Interest	The following table presents the changes in redeemable noncontrolling interests for the years ended December 31: 2016 2015 2014 (in millions) Beginning balance $ 43 $ 39 $ 29 Net income attributable to redeemable noncontrolling interests 4 2 4 Distributions to redeemable noncontrolling interests (1 ) — (1 ) Capital contributions from redeemable noncontrolling interests 118 2 7 Ending balance $ 164 $ 43 $ 39
Condensed Income Statement	The following table presents the attribution of net income (loss) to the Company and the noncontrolling interests for the years ended December 31: 2016 2015 2014 (in millions) Net income $ 374 $ 229 $ 175 Less: Net income (loss) attributable to noncontrolling interests 32 12 (1 ) Less: Net income attributable to redeemable noncontrolling interests 4 2 4 Net income attributable to the Company $ 338 $ 215 $ 172

Capitalization (Tables)

Capitalization (Tables)	12 Months Ended
	Dec. 31, 2016
Southern Company Gas [Member]
Debt Instrument [Line Items]
Schedule of Capitalization	Successor Predecessor Successor Predecessor 2016 2015 2016 2015 (in millions) (in millions) (percent of total) (percent of total) Long-Term Debt: Long-term notes payable — 1.47% to 9.10% due 2016-2046 (a) $ 3,887 $ 3,181 Other long-term debt — First mortgage bonds — 2.66% to 6.58% due 2016-2038 (b) 625 375 Gas facility revenue bonds — Variable rate (1.28% at 1/1/17) due 2022-2033 200 200 Total other long-term debt 825 575 Unamortized fair value adjustment of long-term debt 578 68 Unamortized debt discount (9 ) (4 ) Total long-term debt (annual interest requirement — $207 million) 5,281 3,820 Less amount due within one year 22 545 Long-term debt excluding amount due within one year 5,259 3,275 36.6 % 45.2 % Common Stockholder's Equity: Common stock — 2016: par value $0.01 per share — 2015 par value $5 per share Authorized — 2016: 100 million shares — 2015: 750 million shares Outstanding — 2016: 100 shares — 2015: 120.4 million shares Treasury — 2016: no shares — 2015: 0.2 million shares Paid-in capital 9,095 2,702 Treasury, at cost — (8 ) Retained earnings (accumulated deficit) (12 ) 1,421 Accumulated other comprehensive income (loss) 26 (186 ) Total common stockholder's equity 9,109 3,929 63.4 54.2 Noncontrolling interest — 46 — 0.6 Total stockholders' equity 9,109 3,975 Total Capitalization $ 14,368 $ 7,250 100.0 % 100.0 % (a) Long-term notes payable maturities are as follows: $22 million in 2017 ( 7.20% ); $155 million in 2018 ( 3.50% ); $300 million in 2019 ( 5.25% ); $330 million in 2021 ( 3.50% to 9.10% ); and $3.1 billion in 2022 - 2046 ( 2.45% to 8.70% ). (b) First mortgage bonds maturities are as follows: $50 million in 2019 ( 4.70% ) and $575 million in 2023 - 2038 ( 2.66% to 6.58% ).

Quarterly Financial Informati48

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for 2016 and 2015 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 2016 $ 3,992 $ 940 $ 489 $ 0.53 $ 0.53 $ 0.5425 $ 51.73 $ 46.00 June 2016 4,459 1,185 623 0.67 0.66 0.5600 53.64 47.62 September 2016 6,264 1,917 1,139 1.18 1.17 0.5600 54.64 50.00 December 2016 5,181 587 197 0.20 0.20 0.5600 52.23 46.20 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
Alabama Power [Member]
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2016 $ 1,331 $ 333 $ 156 June 2016 1,444 430 213 September 2016 1,785 650 351 December 2016 1,329 252 102 March 2015 $ 1,401 $ 346 $ 169 June 2015 1,455 398 200 September 2015 1,695 555 295 December 2015 1,217 264 121
Georgia Power [Member]
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (in millions) March 2016 $ 1,872 $ 509 $ 269 June 2016 2,051 656 349 September 2016 2,698 1,054 599 December 2016 1,762 258 113 March 2015 $ 1,978 $ 454 $ 236 June 2015 2,016 554 277 September 2015 2,691 964 551 December 2015 1,641 376 196
Gulf Power [Member]
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in millions) March 2016 $ 335 $ 65 $ 29 June 2016 365 74 34 September 2016 436 90 45 December 2016 349 54 23 March 2015 $ 357 $ 72 $ 37 June 2015 384 69 35 September 2015 429 91 48 December 2015 313 58 28
Mississippi Power [Member]
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) After Dividends on Preferred Stock (in millions) March 2016 $ 257 $ (10 ) $ 11 June 2016 277 (28 ) 2 September 2016 352 9 26 December 2016 277 (166 ) (89 ) March 2015 $ 276 $ 24 $ 35 June 2015 275 12 49 September 2015 341 (66 ) (21 ) December 2015 246 (143 ) (71 )
Southern Power [Member]
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for 2016 and 2015 is as follows: Quarter Ended Operating Revenues Operating Income Net Income Attributable to the Company (in millions) March 2016 $ 315 $ 47 $ 50 June 2016 373 81 89 September 2016 500 134 176 December 2016 389 28 23 March 2015 $ 348 $ 67 $ 33 June 2015 337 75 46 September 2015 401 129 102 December 2015 304 55 34
Southern Company Gas [Member]
Quarterly Financial Information [Line Items]
Summarized quarterly financial data	Summarized quarterly financial information for the successor period of July 1, 2016 through December 31, 2016 and for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 are as follows: Quarter Ended Operating Operating EBIT Net Income (Loss) (in millions) Predecessor - January 1, 2016 through June 30, 2016 March 2016 $ 1,334 $ 348 $ 351 $ 182 June 2016 571 (27 ) (23 ) (51 ) Successor - July 1, 2016 through December 31, 2016 September 2016 $ 543 $ 12 $ 50 $ 4 December 2016 1,109 185 221 110 Predecessor - 2015 March 2015 $ 1,721 $ 364 $ 367 $ 193 June 2015 674 107 111 42 September 2015 584 59 62 11 December 2015 962 216 221 107

Summary of Significant Accoun49

Summary of Significant Accounting Policies - General (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)statesegmentutility	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)statesegmentutility	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Accounting Policies [Line Items]
Other intangible assets, net of amortization	$ 970				$ 317				$ 970	$ 317
Number of traditional operating companies | segment	4								4
Retail Revenues									$ 15,234	14,987	$ 15,550
Net Income (Loss) After Dividends on Preferred and Preference Stock	$ 197	$ 1,139	$ 623	$ 489	271	$ 959	$ 629	$ 508	$ 2,448	2,367	1,963
Southern Company Gas [Member]
Accounting Policies [Line Items]
Number of states in which entity operates | state	7								7
Number of natural gas distribution utilities | utility	7								7
Traditional Operating Companies
Accounting Policies [Line Items]
Number of states in which entity operates | state	4								4
Georgia Power [Member]
Accounting Policies [Line Items]
Retail Revenues									$ 7,772	7,727	8,240
Net Income (Loss) After Dividends on Preferred and Preference Stock	$ 113	599	349	269	196	551	277	236	$ 1,330	1,260	$ 1,225
Southern Power [Member]
Accounting Policies [Line Items]
Other intangible assets, net of amortization					317					$ 317
Net Income (Loss) After Dividends on Preferred and Preference Stock	$ 23	$ 176	$ 89	$ 50	$ 34	$ 102	46	$ 33
Restatement Adjustment | Georgia Power [Member]
Accounting Policies [Line Items]
Retail Revenues							(75)
Net Income (Loss) After Dividends on Preferred and Preference Stock							$ (47)

Summary of Significant Accoun50

Summary of Significant Accounting Policies - Affiliate Transactions (Details)	Dec. 14, 2016USD ($)	Oct. 04, 2016USD ($)	Jun. 27, 2016USD ($)	Jan. 28, 2016USD ($)	Jun. 03, 2015USD ($)	Dec. 31, 2016USD ($)location	Dec. 31, 2016USD ($)location	Dec. 31, 2016USD ($)location	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 01, 2016
Related Party Transaction [Line Items]
Long-term Debt and Capital Lease Obligations, Current						$ 2,587,000,000	$ 2,587,000,000	$ 2,587,000,000	$ 2,674,000,000
Alabama Power [Member]
Related Party Transaction [Line Items]
Ownership percentage, equity method investment						50.00%	50.00%	50.00%
Capital contributions from parent company								$ 260,000,000	22,000,000	$ 28,000,000
Long-term Debt and Capital Lease Obligations, Current						$ 561,000,000	$ 561,000,000	561,000,000	200,000,000
Mississippi Power [Member]
Related Party Transaction [Line Items]
Capital contributions from parent company	$ 400,000,000		$ 225,000,000					627,000,000	277,000,000	451,000,000
Issuance of Promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest				$ 275,000,000	$ 301,000,000			0	301,000,000	0
Long-term Debt and Capital Lease Obligations, Current						629,000,000	629,000,000	629,000,000	728,000,000
Long-term debt affiliated						551,000,000	551,000,000	551,000,000	0
Gulf Power [Member]
Related Party Transaction [Line Items]
Capital contributions from parent company								20,000,000	4,000,000	4,000,000
Long-term Debt and Capital Lease Obligations, Current						87,000,000	87,000,000	87,000,000	110,000,000
Southern Power [Member]
Related Party Transaction [Line Items]
Deferred Project Development Costs									11,000,000
Capital contributions from parent company								1,850,000,000	646,000,000	146,000,000
Long-term Debt and Capital Lease Obligations, Current						$ 560,000,000	$ 560,000,000	$ 560,000,000	403,000,000
Georgia Power [Member]
Related Party Transaction [Line Items]
Number Of Military Bases For Renewable Generation | location						2	2	2
Capital contributions from parent company								$ 594,000,000	62,000,000	549,000,000
Long-term Debt and Capital Lease Obligations, Current						$ 460,000,000	$ 460,000,000	460,000,000	712,000,000
PowerSecure International, Inc. [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount		$ 118,000,000
Southern Natural Gas Company, LLC [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount						2,000,000
Southern Natural Gas Company, LLC [Member] | Southern Company Gas [Member]
Related Party Transaction [Line Items]
Related party transaction, amount						15,000,000
Southern Natural Gas Company, LLC [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount						7,000,000
Southern Natural Gas Company, LLC [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount						$ 35,000,000
Southern Company Services, Inc. [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								460,000,000	438,000,000	400,000,000
Southern Company Services, Inc. [Member] | Mississippi Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								231,000,000	295,000,000	259,000,000
Southern Company Services, Inc. [Member] | Gulf Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								80,000,000	81,000,000	80,000,000
Southern Company Services, Inc. [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								193,000,000	146,000,000	126,000,000
Southern Company Services, Inc. [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								606,000,000	585,000,000	555,000,000
Georgia Power [Member] | Gulf Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								8,000,000	12,000,000	9,000,000
Mississippi Power [Member] | Gulf Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								26,000,000	27,000,000	31,000,000
Alabama Power [Member] | Gulf Power [Member]
Related Party Transaction [Line Items]
Revenue requirements reimbursement								12,000,000	14,000,000	12,000,000
Gulf Power [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Revenue requirements reimbursement								12,000,000	14,000,000	12,000,000
Gulf Power [Member] | Mississippi Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								26,000,000	27,000,000	31,000,000
Gulf Power [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								$ 7,000,000
Gulf Power [Member] | Georgia Power [Member] | Plant Scherer Unit Three [Member]
Related Party Transaction [Line Items]
Long-term Purchase Commitment, Reimbursement Percentage						25.00%	25.00%	25.00%
Southern Company Gas [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount							$ 17,000,000
Southern Company Gas [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount						$ 10,000,000
Southern Power [Member] | Gulf Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								$ 6,800,000
Southern Power [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								265,000,000	179,000,000	144,000,000
Southern Nuclear Operating Company, Inc. [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								249,000,000	243,000,000	234,000,000
Southern Nuclear Operating Company, Inc. [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								666,000,000	681,000,000	643,000,000
Successor [Member] | Southern Company Gas [Member]
Related Party Transaction [Line Items]
Capital contributions from parent company							1,085,000,000
Long-term Debt and Capital Lease Obligations, Current						$ 22,000,000	22,000,000	22,000,000
Successor [Member] | Southern Company Services, Inc. [Member] | Southern Company Gas [Member]
Related Party Transaction [Line Items]
Related party transaction, amount							17,000,000
Successor [Member] | Southern Company Services, Inc. [Member] | Southstar [Member]
Related Party Transaction [Line Items]
Revenue from related parties							9,000,000
Successor [Member] | Southern Company Services, Inc. [Member] | Sequent [Member]
Related Party Transaction [Line Items]
Revenue from related parties							$ 19,000,000
Scenario, Plan [Member] | Alabama Power [Member] | Gulf Power [Member]
Related Party Transaction [Line Items]
Revenue requirements reimbursement								10,000,000
Scenario, Plan [Member] | Gulf Power [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Revenue requirements reimbursement								73,000,000
Southern Natural Gas Company, LLC [Member] | Southern Company Gas [Member]
Related Party Transaction [Line Items]
Ownership percentage, equity method investment											50.00%
Non-Fuel Expense [Member] | Mississippi Power [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								13,000,000	11,000,000	13,000,000
Non-Fuel Expense [Member] | Alabama Power [Member] | Mississippi Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								13,000,000	11,000,000	13,000,000
Non-Fuel Expense [Member] | Gulf Power [Member] | Georgia Power [Member] | Plant Scherer Unit Three [Member]
Related Party Transaction [Line Items]
Reimbursement Revenue								8,000,000	12,000,000	9,000,000
Fuel Purchases [Member] | Mississippi Power [Member] | Alabama Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								0	8,000,000	34,000,000
Fuel Purchases [Member] | Alabama Power [Member] | Mississippi Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount									8,000,000	34,000,000
Purchased Power from Affiliates [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								258,000,000	219,000,000	153,000,000
Operating Lease PPA [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								109,000,000	109,000,000	75,000,000
Operations and Maintenance Expense [Member] | Southern Company Services, Inc. [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								173,000,000	$ 138,000,000	125,000,000
Electric Transmission [Member] | Southern Company Services, Inc. [Member] | Southern Power [Member]
Related Party Transaction [Line Items]
Related party transaction, amount								$ 11,000,000		$ 7,000,000

Summary of Significant Accoun51

Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended			36 Months Ended
	Jul. 31, 2016	Dec. 31, 2019	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2016	Aug. 29, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 5,866		$ 5,866		$ 5,564
Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(2,774)		(2,774)		(1,177)
Deferred income tax credits
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(219)		(219)		(187)
Over recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(203)		(203)		(261)
Property damage reserves-liability
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(177)		(177)		(178)
Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(110)		(110)		(35)
Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(10)		(10)		(45)
Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			3,959		3,959		3,440
Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			1,080		1,080		481
Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			355		355		299
Loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			243		243		248
Environmental remediation-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			491		491		78
Under recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			273		273		142
Property damage reserves-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			206		206		92
Kemper IGCC
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			201		201		216
Vacation pay
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 182		182		178
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			1 year
Long-term debt fair value adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 155		155		0
Deferred PPA charges
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			141		141		163
Nuclear outage
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			97		97		88
Fuel-hedging-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			35		35		225
Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			351		351		283
Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 1,590		1,590		1,514
Maximum [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Life of new issue			50 years
Power purchase agreement period			7 years
Maximum [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory Liability, Amortization Period			4 years
Maximum [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			15 years
Maximum [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			50 years
Maximum [Member] | Asset Group 1 [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			10 years
Maximum [Member] | Fuel-hedging-asset
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			5 years
Maximum [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			11 years
Maximum [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			70 years
Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel Hedging Assets and Liabilities, Amortization Period			3 years 6 months
Total assets (liabilities), net			$ 1,047		1,047		791
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Medicare drug subsidy obligation related to subsidiary			16		16		17
Amortization of regulatory assets				$ 123
Alabama Power [Member] | Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(684)		(684)		(722)
Alabama Power [Member] | Deferred income tax credits
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(65)		(65)		(70)
Alabama Power [Member] | Over recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(97)
Alabama Power [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(23)		(23)		(8)
Alabama Power [Member] | Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(40)
Alabama Power [Member] | Natural disaster reserve
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(69)		(69)		(75)
Alabama Power [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			947		947		903
Alabama Power [Member] | Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			12		12
Alabama Power [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			50		50		53
Alabama Power [Member] | Loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			68		68		75
Alabama Power [Member] | Under recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			76		76
Alabama Power [Member] | Vacation pay
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			69		69		66
Alabama Power [Member] | Nuclear outage
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			70		70		53
Alabama Power [Member] | Fuel-hedging-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			1		1		55
Alabama Power [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 69		69		76
Alabama Power [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			11 years
Alabama Power [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 526		526		522
Alabama Power [Member] | Maximum [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Life of new issue			50 years
Alabama Power [Member] | Maximum [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			15 years
Alabama Power [Member] | Maximum [Member] | Deferred income tax charges
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			15 years
Alabama Power [Member] | Maximum [Member] | Nuclear outage
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			10 years
Alabama Power [Member] | Maximum [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			50 years
Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 320		320		296
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory asset						$ 63
Life of new issue			40 years
Gulf Power [Member] | Over Under Recovered Regulatory Clause Revenues [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			1 year
Gulf Power [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ (2)		(2)		(3)
Gulf Power [Member] | Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(278)		(278)		(262)
Gulf Power [Member] | Over recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(23)		(23)		(22)
Gulf Power [Member] | Property damage reserves-liability
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(40)		(40)		(38)
Gulf Power [Member] | Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(1)
Gulf Power [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			160		160		147
Gulf Power [Member] | Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			7		7
Gulf Power [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			18		18		16
Gulf Power [Member] | Loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			18		18		15
Gulf Power [Member] | Environmental remediation-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 44		44		46
Gulf Power [Member] | Vacation pay
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			1 year
Gulf Power [Member] | Deferred PPA charges
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 141		141		163
Gulf Power [Member] | Ash Pond Closure [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 75		75		29
Gulf Power [Member] | Fuel Hedging Assets and Liabilities [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			5 years
Gulf Power [Member] | Fuel-hedging-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 24		24		104
Gulf Power [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			66		66		4
Gulf Power [Member] | Regulatory asset, offset to other cost of removal
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			29		29		29
Gulf Power [Member] | Deferred Return On Transmission Upgrades [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			25		25		10
Gulf Power [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 56		56		59
Gulf Power [Member] | Maximum [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			14 years
Gulf Power [Member] | Maximum [Member] | Deferred PPA charges
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			7 years
Gulf Power [Member] | Maximum [Member] | Deferred Income Tax Charge, AROs, Cost Of Removal Obligations, Deferred Income Tax Credits [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			65 years
Southern Company Gas [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			12 months
Southern Company Gas [Member] | Vacation pay
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			1 year
Southern Company Gas [Member] | Maximum [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			11 years
Southern Company Gas [Member] | Maximum [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			10 years
Southern Company Gas [Member] | Maximum [Member] | Long-term debt fair value adjustment
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			22 years
Southern Company Gas [Member] | Maximum [Member] | Financial Instrument Hedging [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			2 years
Southern Company Gas [Member] | Maximum [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			4 years
Southern Company Gas [Member] | Maximum [Member] | Deferred Income Tax Charges and Other Cost of Removal Obligations [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			30 years
Southern Company Gas [Member] | Successor [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ (715)		(715)
Southern Company Gas [Member] | Successor [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(22)		(22)
Southern Company Gas [Member] | Successor [Member] | Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(1,616)		(1,616)
Southern Company Gas [Member] | Successor [Member] | Financial Instrument Hedging [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(21)		(21)
Southern Company Gas [Member] | Successor [Member] | Over recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(104)		(104)
Southern Company Gas [Member] | Successor [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(18)		(18)
Southern Company Gas [Member] | Successor [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			325		325
Southern Company Gas [Member] | Successor [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			58		58
Southern Company Gas [Member] | Successor [Member] | Under recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			118		118
Southern Company Gas [Member] | Successor [Member] | Long-term debt fair value adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			154		154
Southern Company Gas [Member] | Successor [Member] | Environmental Remediation [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			411		411
Southern Company Gas [Member] | Successor [Member] | Financial Instrument Hedging [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 0		0
Southern Company Gas [Member] | Predecessor [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(987)
Southern Company Gas [Member] | Predecessor [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(27)
Southern Company Gas [Member] | Predecessor [Member] | Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(1,591)
Southern Company Gas [Member] | Predecessor [Member] | Financial Instrument Hedging [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							0
Southern Company Gas [Member] | Predecessor [Member] | Over recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(87)
Southern Company Gas [Member] | Predecessor [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							(20)
Southern Company Gas [Member] | Predecessor [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							125
Southern Company Gas [Member] | Predecessor [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							47
Southern Company Gas [Member] | Predecessor [Member] | Under recovered regulatory clause revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							69
Southern Company Gas [Member] | Predecessor [Member] | Long-term debt fair value adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							66
Southern Company Gas [Member] | Predecessor [Member] | Environmental Remediation [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							401
Southern Company Gas [Member] | Predecessor [Member] | Financial Instrument Hedging [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net							30
Southern Company Gas [Member] | Predecessor [Member] | Over Under Recovered Regulatory Clause Revenues [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			9 years
Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 737		737		667
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period	5 years
Mississippi Power [Member] | Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(170)		(170)		(167)
Mississippi Power [Member] | Property damage reserves-liability
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(68)		(68)		(64)
Mississippi Power [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(16)		(16)		(11)
Mississippi Power [Member] | Kemper IGCC [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			201		201		216
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory asset			$ 97		97
Mississippi Power [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			14 years
Mississippi Power [Member] | Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 83		83		70
Mississippi Power [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 42		42		27
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			50 years
Mississippi Power [Member] | Fuel Hedging Assets and Liabilities [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			3 years
Mississippi Power [Member] | Fuel-hedging-asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 7		7		50
Mississippi Power [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			1 year
Mississippi Power [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 53		53		36
Mississippi Power [Member] | Property Tax [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 37		37		27
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			12 months
Mississippi Power [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 362		362		291
Mississippi Power [Member] | Retiree Benefit Plans - Regulatory Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 173		173		163
Mississippi Power [Member] | Plant Daniel Units 3 and 4
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			10 years
Mississippi Power [Member] | Plant Daniel Units 3 and 4 | Plant Daniel Units 3 and 4
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 33		33		29
Mississippi Power [Member] | Amortization Period One | Fuel Hedging Assets and Liabilities [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			2 years
Mississippi Power [Member] | Amortization Period Two | Fuel Hedging Assets and Liabilities [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			7 years
Mississippi Power [Member] | Amortization Period Three | Fuel Hedging Assets and Liabilities [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			10 years
Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 3,506		3,506		2,933
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Refueling cycles maximum period			24 months
Georgia Power [Member] | Other cost of removal obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 3		3		(31)
Georgia Power [Member] | Deferred income tax credits
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(121)		(121)		(105)
Georgia Power [Member] | Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			(39)		(39)		(2)
Georgia Power [Member] | Retiree Benefit Plans
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 1,348		1,348		1,307
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			13 years
Georgia Power [Member] | Deferred income tax charges
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 26		26
Georgia Power [Member] | Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			893		893		411
Georgia Power [Member] | Other regulatory assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 97		97		110
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			24 months
Amortization of regulatory assets			$ 46
Georgia Power [Member] | Loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			137		137		150
Georgia Power [Member] | Vacation pay
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 91		91		91
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			1 year
Georgia Power [Member] | Canceled Construction Projects [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 44		44		56
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			9 years
Georgia Power [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			$ 166		166		171
Georgia Power [Member] | Obsolete Inventories of Retired Units [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			31		31
Georgia Power [Member] | Storm damage reserves
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			206		206		92
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Amortization of regulatory assets					185
Georgia Power [Member] | Deferred Income Tax Charge [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total assets (liabilities), net			681		681		$ 683
Georgia Power [Member] | Plant Mitchell Unit 3 [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Net Book Value Of Planned Units Retirements			$ 12		$ 12
Georgia Power [Member] | Maximum [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Life of new issue			36 years
Georgia Power [Member] | Maximum [Member] | Deferred Income Tax Charge, AROs, Cost Of Removal Obligations, Deferred Income Tax Credits [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			70 years
Georgia Power [Member] | Maximum [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			10 years
Georgia Power [Member] | Scenario, Forecast [Member] | Remaining net book value of retired assets
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Amortization of regulatory assets		$ 5
Deferred Income Tax Charge, AROs, Cost Of Removal Obligations, Deferred Income Tax Credits [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]
Regulatory amortization period			49 years

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Government Grants, Revenue, Taxes, Concentration Risk (Details) - USD ($) $ in Millions	Apr. 08, 2016	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2010
Accounting Policies [Line Items]
Deferred income tax assets		$ 9,495		$ 9,495	$ 6,683		$ 9,495
Maximum [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				10.00%
Maximum percentage of uncollectible accounts (less than)				1.00%
Gulf Power [Member]
Accounting Policies [Line Items]
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue				10.00%
Deferred income tax assets		244		$ 244	216		244
Gulf Power [Member] | Maximum [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				10.00%
Maximum percentage of uncollectible accounts (less than)				1.00%
Gulf Power [Member] | Minimum [Member]
Accounting Policies [Line Items]
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue				10.00%
Southern Company Gas [Member]
Accounting Policies [Line Items]
Period for collection of revenue prior to billings				24 months
Southern Company Gas [Member] | Maximum [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				10.00%
Maximum percentage of uncollectible accounts (less than)				1.00%
Southern Company Gas [Member] | Successor [Member]
Accounting Policies [Line Items]
Deferred income tax assets		598		$ 598			598
Excise Taxes Collected		32
Southern Company Gas [Member] | Predecessor [Member]
Accounting Policies [Line Items]
Deferred income tax assets					438
Excise Taxes Collected			$ 57		103	$ 133
Mississippi Power [Member]
Accounting Policies [Line Items]
Percentage Of Wholesale Customers To Operating Revenue				19.80%
Period Of Contract Cancellation Notices Of Wholesale Customers				10 years
Deferred income tax assets		1,024		$ 1,024	1,400		1,024
Grants received from Department of Energy							382
Mississippi Power [Member] | Maximum [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				10.00%
Maximum percentage of uncollectible accounts (less than)				1.00%
Mississippi Power [Member] | Kemper IGCC [Member]
Accounting Policies [Line Items]
Grants expected to be received from Department of Energy		25		$ 25			25	$ 270
Grants received from Department of Energy	$ 137			140			245
Southern Power [Member]
Accounting Policies [Line Items]
Deferred income tax assets		2,937		$ 2,937	$ 794		2,937
Reduction in tax basis of assets				50.00%
Southern Power [Member] | Sales Revenue, Goods, Net [Member] | Georgia Power [Member] | Customer Concentration Risk [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				16.50%	15.80%	10.10%
Southern Power [Member] | Sales Revenue, Goods, Net [Member] | Duke Energy Corporation | Customer Concentration Risk [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				7.80%	8.20%	9.10%
Southern Power [Member] | Sales Revenue, Goods, Net [Member] | San Diego Gas & Electric Company | Customer Concentration Risk [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				5.70%	6.10%	2.90%
Southern Power [Member] | Sales Revenue, Goods, Net [Member] | FPL | Customer Concentration Risk [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				0.00%	10.70%	9.70%
Georgia Power [Member]
Accounting Policies [Line Items]
Federal tax credits				$ 83
Deferred income tax assets		2,382		$ 2,382	$ 2,077		2,382
Georgia Power [Member] | Maximum [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				10.00%
Maximum percentage of uncollectible accounts (less than)				1.00%
Alabama Power [Member]
Accounting Policies [Line Items]
Deferred income tax assets		1,544		$ 1,544	1,511		1,544
Alabama Power [Member] | Maximum [Member]
Accounting Policies [Line Items]
Maximum revenue from a single customer or industry (more than)				10.00%
Maximum percentage of uncollectible accounts (less than)				1.00%
Investment Tax And Other Credit Carryforward [Member] | Georgia Power [Member]
Accounting Policies [Line Items]
Deferred income tax assets		345		$ 345			$ 345
Included In Operating Expenses [Member] | Southern Company Gas [Member] | Successor [Member]
Accounting Policies [Line Items]
Excise Taxes Collected		$ 31
Included In Operating Expenses [Member] | Southern Company Gas [Member] | Predecessor [Member]
Accounting Policies [Line Items]
Excise Taxes Collected			$ 56		$ 101	$ 130

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Property, Plant, and Equipment (Details) $ in Millions	1 Months Ended	6 Months Ended		12 Months Ended
	Jul. 31, 2016	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)Property	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation		$ 48,836		$ 48,836	$ 41,648
Transmission		11,156		11,156	10,544
Distribution		18,418		18,418	17,670
General		4,629		4,629	4,377
Plant acquisition adjustment		126		126	123
Electric Utility Plant in Service		83,165		83,165	74,362
Transportation and distribution		11,996		11,996	0
Utility plant in service		95,161		95,161	74,362
Information technology equipment and software		544		544	222
Communications equipment		424		424	418
Storage facilities		1,463		1,463	0
Other		824		824	116
Other plant in service		3,255		3,255	756
Total plant in service		98,416		98,416	75,118
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Less: Accumulated amortization		(69)		(69)	(59)
Balance, net of amortization		144		144	152
Accrued property additions at year-end				1,500	844	$ 528
Capital Lease Obligations
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Non-cash property additions recognized				18	13	25
Office building
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Capital leased assets, gross		61		61	61
Nitrogen plant
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Capital leased assets, gross		83		83	83
Computer-related equipment
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Capital leased assets, gross		63		63	61
Gas pipeline
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Capital leased assets, gross		6		6	6
Southern Power [Member]
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end				$ 251	257	1
Alabama Power and Georgia Power [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Refueling cycles for minimum period				18 months
Refueling cycles maximum period				24 months
Southern Company Gas [Member] | Successor [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Utility plant in service		11,996		$ 11,996
Information technology equipment and software		324		324
Storage facilities		1,463		1,463
Other		725		725
Other plant in service		2,512		2,512
Total plant in service		14,508		$ 14,508
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end		63
Southern Company Gas [Member] | Predecessor [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Utility plant in service					9,912
Information technology equipment and software					415
Storage facilities					1,255
Other					570
Other plant in service					2,240
Total plant in service					12,152
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end			$ 41		48	31
Alabama Power [Member]
Property, Plant and Equipment [Line Items]
Number of units for which outage operations and maintenance expenses accrued | Property				2
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation		13,551		$ 13,551	12,820
Transmission		3,921		3,921	3,773
Distribution		6,707		6,707	6,432
General		1,840		1,840	1,713
Plant acquisition adjustment		12		12	12
Total plant in service		26,031		26,031	24,750
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end				$ 84	121	8
Period over which deferred costs are being amortized to nuclear operations and maintenance expenses				18 months
Georgia Power [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation		16,668		$ 16,668	15,386
Transmission		5,779		5,779	5,355
Distribution		9,553		9,553	9,151
General		1,813		1,813	1,921
Plant acquisition adjustment		28		28	28
Total plant in service		33,841		$ 33,841	31,841
Refueling cycles for minimum period				18 months
Refueling cycles maximum period				24 months
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end				$ 336	387	154
Gulf Power [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation		3,001		3,001	2,974
Transmission		706		706	691
Distribution		1,241		1,241	1,196
General		191		191	182
Plant acquisition adjustment		1		1	2
Total plant in service		5,140		5,140	5,045
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end				33	20	42
Mississippi Power [Member]
Property, Plant and Equipment [Line Items]
Regulatory amortization period	5 years
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation		2,632		2,632	2,723
Transmission		712		712	688
Distribution		916		916	891
General		520		520	503
Plant acquisition adjustment		85		85	81
Total plant in service		$ 4,865		4,865	4,886
Capital Leases, Balance Sheet, Assets by Major Class, Net [Abstract]
Accrued property additions at year-end				$ 78	$ 105	$ 114
Kemper IGCC [Member] | Mississippi Power [Member]
Property, Plant and Equipment [Line Items]
Regulatory amortization period					10 years
Maximum [Member] | Southern Power [Member] | Natural Gas Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life				45 years
Maximum [Member] | Southern Power [Member] | Biomass Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life				40 years
Maximum [Member] | Southern Power [Member] | Solar Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life				35 years
Maximum [Member] | Southern Power [Member] | Wind Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life				30 years

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Depreciation and Amortization (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Accumulated depreciation PPE		$ 29,852	$ 24,253
Other Cost of Removal Obligations		$ 2,748	$ 1,162
Utility Plant in Service
Property, Plant and Equipment [Line Items]
Depreciation of cost of utility plant in service, composite straight-line rate		3.00%	3.00%	3.10%
Accumulated depreciation PPE		$ 29,300	$ 23,700
Other Plant in Service
Property, Plant and Equipment [Line Items]
Accumulated depreciation PPE		$ 550	$ 510
Minimum [Member] | Other Plant in Service
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		3 years
Maximum [Member] | Other Plant in Service
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		65 years
Mississippi Power [Member]
Property, Plant and Equipment [Line Items]
Regulatory amortization period	5 years
Depreciation of cost of utility plant in service, composite straight-line rate		4.20%	4.70%	3.30%
Accumulated depreciation PPE		$ 1,289	$ 1,262
Other Cost of Removal Obligations		$ 170	$ 165
Gulf Power [Member]
Property, Plant and Equipment [Line Items]
Depreciation of cost of utility plant in service, composite straight-line rate		3.50%	3.50%	3.60%
Accumulated depreciation PPE		$ 1,382	$ 1,296
Other Cost of Removal Obligations		249	233
Southern Power [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation PPE		$ 1,484	1,248
Southern Power [Member] | Maximum [Member] | Natural Gas Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life		45 years
Southern Power [Member] | Maximum [Member] | Solar Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life		35 years
Southern Power [Member] | Maximum [Member] | Wind Generating Facility [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation, Useful Life		30 years
Southern Company Gas [Member] | Successor [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation PPE		$ 4,439
Other Cost of Removal Obligations		$ 1,616
Southern Company Gas [Member] | Predecessor [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation PPE			2,775
Other Cost of Removal Obligations			$ 1,538
Southern Company Gas [Member] | Utility Plant in Service | Successor [Member]
Property, Plant and Equipment [Line Items]
Depreciation of cost of utility plant in service, composite straight-line rate		2.80%
Southern Company Gas [Member] | Utility Plant in Service | Predecessor [Member]
Property, Plant and Equipment [Line Items]
Depreciation of cost of utility plant in service, composite straight-line rate			2.70%	2.70%
Southern Company Gas [Member] | Minimum [Member] | Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		5 years
Southern Company Gas [Member] | Minimum [Member] | Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		40 years
Southern Company Gas [Member] | Maximum [Member] | Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		15 years
Southern Company Gas [Member] | Maximum [Member] | Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		60 years
Southern Company Gas [Member] | Maximum [Member] | Other Assets [Member]
Property, Plant and Equipment [Line Items]
Plant in service, estimated useful lives		65 years
Georgia Power [Member]
Property, Plant and Equipment [Line Items]
Depreciation of cost of utility plant in service, composite straight-line rate		2.80%	2.70%	2.70%
Regulatory liability amortization		$ 14	$ 14	$ 14
Accumulated depreciation PPE		11,317	10,903
Alabama Power [Member]
Property, Plant and Equipment [Line Items]
Regulatory liability amortization				$ 120
Accumulated depreciation PPE		9,112	8,736
Other Cost of Removal Obligations		$ 684	$ 722
Alabama Power [Member] | Utility Plant in Service
Property, Plant and Equipment [Line Items]
Depreciation of cost of utility plant in service, composite straight-line rate		3.00%	2.90%	3.30%
Settlement Agreement [Member] | Gulf Power [Member]
Property, Plant and Equipment [Line Items]
Other Cost of Removal Obligations		$ 62.5
Kemper IGCC [Member] | Mississippi Power [Member]
Property, Plant and Equipment [Line Items]
Regulatory amortization period			10 years

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 3,759	$ 2,201
Liabilities incurred	66	662
Liabilities settled	(171)	(37)
Accretion	162	115
Cash flow revisions	698	818
Balance at end of year	4,514	3,759
Alabama Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	1,448	829
Liabilities incurred	5	402
Liabilities settled	(25)	(3)
Accretion	73	53
Cash flow revisions	32	167
Balance at end of year	1,533	1,448
Georgia Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	1,916	1,255
Liabilities incurred	0	6
Liabilities settled	(123)	(30)
Accretion	77	56
Cash flow revisions	662	629
Balance at end of year	2,532	1,916
Gulf Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	130	17
Liabilities incurred	1	105
Liabilities settled	(1)	(1)
Accretion	4	2
Cash flow revisions	2	7
Balance at end of year	136	130
Mississippi Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	177	48
Liabilities incurred	15	101
Liabilities settled	(23)	(3)
Accretion	5	4
Cash flow revisions	5	27
Balance at end of year	179	177
Southern Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	21	13
Liabilities incurred	42	7
Accretion	1	1
Balance at end of year	64	21
Plant Scholz | Gulf Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 29
Balance at end of year		$ 29

Summary of Significant Accoun56

Summary of Significant Accounting Policies - Nuclear Decommissiong (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	$ 1,606	$ 1,512
Proceeds from sale of securities held in external trust funds	1,200	1,400	$ 900
Increase (decrease) in fair value of securities related to nuclear decommissioning	114	11	98
Plant Farley [Member]
Decommissioning
Total site study costs	1,442
Plant Farley [Member] | Spent fuel management
Decommissioning
Total site study costs	0
Plant Hatch
Decommissioning
Total site study costs	902
Plant Vogtle Nuclear Units One and Two [Member]
Decommissioning
Total site study costs	804
Equity Securities
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	878	817
Debt Securitie
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	685	654
Other Securities
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	41	38
Unrealized Loss | Securities Held in Funds
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in fair value of securities related to nuclear decommissioning		(83)
Unrealized Gain | Securities Held in Funds
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in fair value of securities related to nuclear decommissioning	48		19
Alabama Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Decommissioning Fund Investments Net Of Foreign Currency	790	734
Nuclear decommissioning trusts, at fair value	792	737
Proceeds from sale of securities held in external trust funds	351	438	244
Increase (decrease) in fair value of securities related to nuclear decommissioning	76	8	54
Accumulated Provisions for Decommissioning
Accumulated Provisions for Decommissioning	809	754
Decommissioning
Total site study costs	$ 1,442
Significant assumption of inflation rate used to determine the costs for rate making (as percent)	4.50%
Significant assumption of trust earnings rate used to determine the costs for rate making (as percent)	7.00%
Alabama Power [Member] | Accumulated provisions for the external decommissioning trust funds
Accumulated Provisions for Decommissioning
Accumulated Provisions for Decommissioning		734
Alabama Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member]
Accumulated Provisions for Decommissioning
Accumulated Provisions for Decommissioning	$ 19	20
Alabama Power [Member] | Plant Farley [Member] | Plant Farley [Member]
Decommissioning
Beginning Year	2,037
Completion Year	2,076
Alabama Power [Member] | Plant Farley [Member] | Accumulated provisions for the external decommissioning trust funds
Accumulated Provisions for Decommissioning
Accumulated Provisions for Decommissioning	$ 790	734
Alabama Power [Member] | Plant Farley [Member] | Radiated structures
Decommissioning
Total site study costs	1,362
Alabama Power [Member] | Plant Farley [Member] | Non-radiated structures
Decommissioning
Total site study costs	80
Alabama Power [Member] | Equity Securities
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	552	521
Alabama Power [Member] | Debt Securitie
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	208	191
Alabama Power [Member] | Other Securities
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	30	22
Alabama Power [Member] | Securities Held in Funds
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in fair value of securities related to nuclear decommissioning		(57)	19
Alabama Power [Member] | Unrealized Gain | Securities Held in Funds
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in fair value of securities related to nuclear decommissioning	34
Georgia Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Fair market value of fund's securities on loan under the Funds' managers' securities lending program	56	76
Fair value of collateral received	58	78
Decommissioning Fund Investments Net Of Foreign Currency	814	775
Nuclear decommissioning trusts, at fair value	814	775
Increase (decrease) in fair value of securities related to nuclear decommissioning	$ 38	3	44
Decommissioning
Significant assumption of inflation rate used to determine the costs for rate making (as percent)	2.40%
Significant assumption of trust earnings rate used to determine the costs for rate making (as percent)	4.40%
Georgia Power [Member] | Plant Hatch
Decommissioning
Beginning Year	2,034
Completion Year	2,075
Total site study costs	$ 902
Amount expensed for rate making purpose				$ 4
Georgia Power [Member] | Plant Hatch | Accumulated provisions for the external decommissioning trust funds
Accumulated Provisions for Decommissioning
Accumulated Provisions for Decommissioning	511	487
Georgia Power [Member] | Plant Hatch | Radiated structures
Decommissioning
Total site study costs	678
Georgia Power [Member] | Plant Hatch | Spent fuel management
Decommissioning
Total site study costs	160
Georgia Power [Member] | Plant Hatch | Non-radiated structures
Decommissioning
Total site study costs	$ 64
Georgia Power [Member] | Plant Vogtle Nuclear Units One and Two [Member]
Decommissioning
Beginning Year	2,047
Completion Year	2,079
Total site study costs	$ 804
Georgia Power [Member] | Plant Vogtle Nuclear Units One and Two [Member] | Accumulated provisions for the external decommissioning trust funds
Accumulated Provisions for Decommissioning
Accumulated Provisions for Decommissioning	303	288
Georgia Power [Member] | Plant Vogtle Nuclear Units One and Two [Member] | Radiated structures
Decommissioning
Total site study costs	568
Georgia Power [Member] | Plant Vogtle Nuclear Units One and Two [Member] | Spent fuel management
Decommissioning
Total site study costs	147
Georgia Power [Member] | Plant Vogtle Nuclear Units One and Two [Member] | Non-radiated structures
Decommissioning
Total site study costs	89
Georgia Power [Member] | Plant Vogtle [Member]
Decommissioning
Amount expensed for rate making purpose				$ 2
Georgia Power [Member] | Equity Securities
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	326	296
Georgia Power [Member] | Debt Securitie
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	477	463
Georgia Power [Member] | Other Securities
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	11	16
Georgia Power [Member] | Securities Investment [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning trusts, at fair value	803	980	$ 669
Georgia Power [Member] | Securities Held in Funds
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in fair value of securities related to nuclear decommissioning	$ 14
Georgia Power [Member] | Unrealized Gain (Loss or Write-down)1 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Increase (decrease) in fair value of securities related to nuclear decommissioning		$ (26)

Summary of Significant Accoun57

Summary of Significant Accounting Policies - AFUC and Interest Capitalized (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Line Items]
Allowance for equity funds used during construction			$ 202	$ 226	$ 245
AFUDC, net of income taxes			11.40%	12.80%	16.00%
Interest, net of amounts capitalized			$ 1,100	$ 809	$ 732
Net cash paid for capitalized interest			125	124	111
Georgia Power [Member]
Accounting Policies [Line Items]
Allowance for equity funds used during construction			$ 48	$ 40	$ 45
Composite rate used for allowance for funds used during construction	6.90%		6.90%	6.50%	5.60%
Allowance for Funds Used During Construction, Capitalized Interest			$ 68	$ 56	$ 62
AFUDC, net of income taxes			4.60%	3.90%	4.60%
Interest, net of amounts capitalized			$ 375	$ 353	$ 319
Net cash paid for capitalized interest			20	16	18
Alabama Power [Member]
Accounting Policies [Line Items]
Allowance for equity funds used during construction			$ 28	$ 60	$ 49
Composite rate used for allowance for funds used during construction	8.40%		8.40%	8.70%	8.80%
AFUDC, net of income taxes			4.20%	9.30%	7.90%
Interest, net of amounts capitalized			$ 277	$ 250	$ 231
Net cash paid for capitalized interest			11	22	18
Mississippi Power [Member]
Accounting Policies [Line Items]
Allowance for equity funds used during construction			$ 124	$ 110	$ 136
Composite rate used for allowance for funds used during construction	6.50%		6.50%	5.99%	6.91%
Interest, net of amounts capitalized			$ 50	$ 45	$ 7
Net cash paid for capitalized interest			$ 49	$ 66	$ 69
Gulf Power [Member]
Accounting Policies [Line Items]
Composite rate used for allowance for funds used during construction	5.73%		5.73%	5.73%	5.73%
AFUDC, net of income taxes			0.00%	10.80%	10.93%
Interest, net of amounts capitalized			$ 53	$ 52	$ 48
Net cash paid for capitalized interest			$ 0	6	5
Successor [Member] | Southern Company Gas [Member]
Accounting Policies [Line Items]
Interest, net of amounts capitalized	$ 135
Successor [Member] | Atlanta Gas Light
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)	4.05%
Successor [Member] | Chattanooga Gas [Member]
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)	3.71%
Successor [Member] | Elizabethtown Gas [Member]
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)	0.84%
Successor [Member] | Nicor Gas [Member]
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)	1.50%
Predecessor [Member] | Southern Company Gas [Member]
Accounting Policies [Line Items]
Interest, net of amounts capitalized		$ 119		$ 181	$ 187
Predecessor [Member] | Atlanta Gas Light
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)		4.05%		8.10%	8.10%
Predecessor [Member] | Chattanooga Gas [Member]
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)		3.71%		7.41%	7.41%
Predecessor [Member] | Elizabethtown Gas [Member]
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)		0.84%		1.69%	0.44%
Predecessor [Member] | Nicor Gas [Member]
Accounting Policies [Line Items]
Allowance for funds under construction rate (as percent)		1.50%		0.82%	0.24%

Summary of Significant Accoun58

Summary of Significant Accounting Policies - Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2015
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill	$ 6,251	$ 6,251		$ 6,251	$ 2
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	957	957		957
Accumulated Amortization	(62)	(62)		(62)	(12)
Other Intangible Assets, Net	895	895		895
Total other intangible assets, gross	1,032	1,032		1,032
Total other intangible assets, net	970	970		970	317
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
2,017	108	108		108
2,018	93	93		93
2,019	74	74		74
2,020	63	63		63
2,021	56	56		56
Amortization of intangible assets				50	3	$ 3
Customer relationships
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	268	268		268
Accumulated Amortization	(32)	(32)		(32)
Other Intangible Assets, Net	236	236		236
Trade names
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	158	158		158
Accumulated Amortization	(5)	(5)		(5)
Other Intangible Assets, Net	153	153		153
Patents
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	4	4		4
Accumulated Amortization	0	0		0
Other Intangible Assets, Net	4	4		4
Backlog
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	5	5		5
Accumulated Amortization	(1)	(1)		(1)
Other Intangible Assets, Net	4	4		4
Storage and transportation contracts
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	64	64		64
Accumulated Amortization	(2)	(2)		(2)
Other Intangible Assets, Net	62	62		62
Software and other
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	2	2		2
Accumulated Amortization	0	0		0
Other Intangible Assets, Net	2	2		2
PPA fair value adjustments
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	456	456		456
Accumulated Amortization	(22)	(22)		(22)
Other Intangible Assets, Net	434	434		$ 434
Minimum [Member] | Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				11 years
Minimum [Member] | Trade names
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				5 years
Minimum [Member] | Patents
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				3 years
Minimum [Member] | Storage and transportation contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				1 year
Minimum [Member] | Software and other
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				1 year
Minimum [Member] | PPA fair value adjustments
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				19 years
Maximum [Member] | Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				26 years
Maximum [Member] | Trade names
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				28 years
Maximum [Member] | Patents
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				10 years
Maximum [Member] | Storage and transportation contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				5 years
Maximum [Member] | Software and other
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				12 years
Maximum [Member] | PPA fair value adjustments
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				20 years
Southern Company Gas [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill impairment testing fair value in excess of carrying value percent						5.00%
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
2,017	73	73		$ 73
2,018	58	58		58
2,019	40	40		40
2,020	28	28		28
2,021	21	21		21
Southern Company Gas [Member] | Predecessor [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill					1,813
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount					177
Accumulated Amortization					(68)
Other Intangible Assets, Net					109
Total other intangible assets, net					109
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
Amortization of intangible assets			$ 8		18	$ 20
Southern Company Gas [Member] | Predecessor [Member] | Customer relationships
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount					132
Accumulated Amortization					(57)
Other Intangible Assets, Net					75
Southern Company Gas [Member] | Predecessor [Member] | Trade names
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount					45
Accumulated Amortization					(11)
Other Intangible Assets, Net					$ 34
Southern Company Gas [Member] | Predecessor [Member] | Minimum [Member] | Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life					11 years
Southern Company Gas [Member] | Predecessor [Member] | Minimum [Member] | Trade names
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life					10 years
Southern Company Gas [Member] | Predecessor [Member] | Maximum [Member] | Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life					14 years
Southern Company Gas [Member] | Predecessor [Member] | Maximum [Member] | Trade names
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life					28 years
Southern Company Gas [Member] | Successor [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill	5,967	5,967		5,967
Goodwill	30
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	400	400		400
Accumulated Amortization	(34)	(34)		(34)
Other Intangible Assets, Net	366	366		366
Total other intangible assets, net	366	366		366
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
Amortization of intangible assets		32
Southern Company Gas [Member] | Successor [Member] | Customer relationships
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	221	221		221
Accumulated Amortization	(30)	(30)		(30)
Other Intangible Assets, Net	191	191		191
Southern Company Gas [Member] | Successor [Member] | Trade names
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	115	115		115
Accumulated Amortization	(2)	(2)		(2)
Other Intangible Assets, Net	113	113		113
Southern Company Gas [Member] | Successor [Member] | Storage and transportation contracts
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	64	64		64
Accumulated Amortization	(2)	(2)		(2)
Other Intangible Assets, Net	62	62		$ 62
Southern Company Gas [Member] | Successor [Member] | Minimum [Member] | Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				11 years
Southern Company Gas [Member] | Successor [Member] | Minimum [Member] | Trade names
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				10 years
Southern Company Gas [Member] | Successor [Member] | Minimum [Member] | Storage and transportation contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				1 year
Southern Company Gas [Member] | Successor [Member] | Maximum [Member] | Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				14 years
Southern Company Gas [Member] | Successor [Member] | Maximum [Member] | Trade names
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				28 years
Southern Company Gas [Member] | Successor [Member] | Maximum [Member] | Storage and transportation contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				5 years
Southern Company [Member] | Backlog
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				5 years
Southern Company [Member] | FCC Licenses [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Other intangible assets not subject to amortization:	75	75		$ 75
Southern Power [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life				19 years
Finite-Lived Intangible Assets, Net [Abstract]
Accumulated Amortization	(22)	(22)		$ (22)	$ (12)
Total other intangible assets, net					317
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
2,017	25	25		25
2,018	25	25		25
2,019	25	25		25
2,020	25	25		25
2,021	25	25		25
Amortization of intangible assets				10	3	3
Gas Distribution Operations [Member] | Southern Company Gas [Member] | Predecessor [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill					1,640
Gas Distribution Operations [Member] | Southern Company Gas [Member] | Successor [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill	4,702	4,702		4,702
Gas Marketing Services [Member] | Southern Company Gas [Member] | Predecessor [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill					$ 173
Gas Marketing Services [Member] | Southern Company Gas [Member] | Successor [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill	$ 1,265	$ 1,265		1,265
Storage and Fuels Reporting Unit [Member] | Southern Company Gas [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Goodwill						$ 14	$ 14
Wholesale Gas Services [Member] | Southern Company Gas [Member] | Successor [Member]
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
Amortization of intangible assets				$ 2

Summary of Significant Accoun59

Summary of Significant Accounting Policies - Intangible Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Line Items]
Other liabilities noncurrent	$ 880	$ 678
Southern Company Gas [Member]
Accounting Policies [Line Items]
Intangible liabilities, accumulated amortization	21
Finite-Lived Intangible Liabilities, Amortization Expense, Maturity Schedule [Abstract]
2,017	29
2,018	24
2,019	17
Intangible Liabilities | Southern Company Gas [Member]
Accounting Policies [Line Items]
Other liabilities noncurrent	$ 91

Summary of Significant Accoun60

Summary of Significant Accounting Policies - Reserves and Leveraged Leases (Details)	12 Months Ended
	Dec. 31, 2016USD ($)kWh	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Aug. 29, 2016USD ($)	Oct. 31, 2015USD ($)
Components of Income from Leveraged Lease
Other Regulatory Assets Current	$ 581,000,000	$ 580,000,000
Other Regulatory Assets Deferred	6,851,000,000	4,989,000,000
Domestic And International Leveraged Lease
Net Investments from Leveraged Lease
Net rentals receivable	1,481,000,000	1,487,000,000
Unearned income	(707,000,000)	(732,000,000)
Investment in leveraged leases	774,000,000	755,000,000
Deferred taxes from leveraged leases	(309,000,000)	(303,000,000)
Net investment in leveraged leases	465,000,000	452,000,000
Components of Income from Leveraged Lease
Pretax leveraged lease income (loss)	25,000,000	20,000,000	$ 24,000,000
Income tax expense	(9,000,000)	(7,000,000)	(9,000,000)
Net leveraged lease income (loss)	$ 16,000,000	13,000,000	15,000,000
Maximum [Member]
Leveraged Lease [Line Items]
Leveraged lease agreement term	45 years
Georgia Power [Member]
Leveraged Lease [Line Items]
Accrual Under Alternate Rate Plan	$ 30,000,000
Components of Income from Leveraged Lease
Other Regulatory Assets Current	193,000,000	213,000,000
Other Regulatory Assets Deferred	2,774,000,000	2,152,000,000
Mississippi Power [Member]
Leveraged Lease [Line Items]
Threshold above which actual damages are charged to the reserve	50,000
Psc approved annual property damage reserve accrual					$ 3,000,000
Components of Income from Leveraged Lease
Retail Accrual Per Annual SRR Rate	4,000,000	3,000,000	3,000,000
Wholesale Accrual Per Annual SRR Rate	300,000	300,000	300,000
Other Regulatory Assets Current	115,000,000	95,000,000
Other Regulatory Assets Deferred	518,000,000	525,000,000
Gulf Power [Member]
Leveraged Lease [Line Items]
Psc approved annual property damage reserve accrual	3,500,000
Threshold above which additional property damage reserves are authorized by PSC	3,500,000
Increase (decrease) in recoverable property damage costs	$ 3,500,000	3,500,000	3,500,000
Recovery period for natural disaster reserve costs	60 days
Cumulative costs limit under PSC order	$ 100,000,000
PSC approved annual uninsured injuries and damages accrual	1,600,000
Threshold above with additional uninsured injuries and damages accruals are authorized by PSC	1,600,000
Liability for claims and claims adjustment expense	1,400,000	0
Estimated liabilities for outstanding claims	0	1,700,000
Accrued reserves	40,000,000	38,000,000
Components of Income from Leveraged Lease
Regulatory asset				$ 63,000,000
Other Regulatory Assets Current	44,000,000	90,000,000
Other Regulatory Assets Deferred	512,000,000	427,000,000
Gulf Power [Member] | Maximum [Member]
Leveraged Lease [Line Items]
PSC approved target level for property damage reserve	55,000,000
Customer surcharge storm recovery costs	$ 4
Customer surcharge storm recovery capacity | kWh	1,000
PSC approved annual uninsured injuries and damages accrual	$ 2,000,000
Gulf Power [Member] | Minimum [Member]
Leveraged Lease [Line Items]
PSC approved target level for property damage reserve	48,000,000
Traditional Operating Companies
Leveraged Lease [Line Items]
Accrued reserves	$ 40,000,000	40,000,000	$ 40,000,000
Current Liabilities [Member] | Gulf Power [Member]
Leveraged Lease [Line Items]
Liability for claims and claims adjustment expense		1,600,000
Deferred Credits and Other Liabilities [Member] | Gulf Power [Member]
Leveraged Lease [Line Items]
Liability for claims and claims adjustment expense		100,000
Mississippi Public Service Commission [Member] | Mississippi Power [Member]
Components of Income from Leveraged Lease
Period To Agree On System Restoration Rider	3 years
Retail [Member]
Components of Income from Leveraged Lease
Proposed Property Damage Reserve	$ 66,000,000
Wholesale [Member]
Components of Income from Leveraged Lease
Proposed Property Damage Reserve	1,000,000
Property Damage Reserves Liability [Member] | Georgia Power [Member]
Components of Income from Leveraged Lease
Regulatory asset	206,000,000	92,000,000
Other Regulatory Assets Current	30,000,000	30,000,000
Other Regulatory Assets Deferred	$ 176,000,000	$ 62,000,000

Summary of Significant Accoun61

Summary of Significant Accounting Policies - Environmental Recovery (Details) - Georgia Power [Member] - USD ($) $ in Millions	1 Months Ended
	Dec. 31, 2013	Dec. 31, 2016
Accounting Policies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation		$ 17
Environmental Remediation Reserve [Member]
Accounting Policies [Line Items]
Costs Recovered Annually Under Rate Plan	$ 2
Other regulatory assets current [Member]
Accounting Policies [Line Items]
Environmental Regulatory Assets		2
Other regulatory assets deferred [Member]
Accounting Policies [Line Items]
Environmental Regulatory Assets		$ 33

Summary of Significant Accoun62

Summary of Significant Accounting Policies - Transmission Receivables/Payables, Cash and Accumulated OCI (loss) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)counterpartycustomer	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 26,612	$ 21,982	$ 20,926	$ 19,764
Original maturities of temporary cash investments	90 days
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	$ (130)
Current period change	(50)	(2)	(53)
Ending Balance	(180)	(130)
Other Comprehensive Income (Loss), Net of Tax	(50)	(2)	(53)
Qualifying Hedges
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	(48)
Current period change	(67)
Ending Balance	(115)	(48)
Marketable Securities
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
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	(82)
Current period change	17
Ending Balance	(65)	(82)
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	(180)	(130)	(128)	(75)
Change in Accumulated OCI (loss) balances [Roll Forward]
Current period change	$ (50)	(2)	(53)
Southern Company Gas [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Original maturities of temporary cash investments	90 days
Atlanta Gas Light
Accumulated Other Comprehensive Income (Loss) [Line Items]
Concentration Risk, Number of Customers | customer	14
Southern Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 5,675	3,264	1,971	1,564
Period of reimbursement of transmission costs	5 years
Restricted cash and cash equivalents noncurrent	$ 13	5
Original maturities of temporary cash investments	90 days
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	$ 4
Current period change	31	1
Ending Balance	35	4
Other Comprehensive Income (Loss), Net of Tax	31	1	0
Southern Power [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	35	4	3	3
Change in Accumulated OCI (loss) balances [Roll Forward]
Current period change	31	1
Mississippi Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 2,943	2,359	2,084	2,177
Original maturities of temporary cash investments	90 days
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	$ (6)
Current period change	2	1	1
Ending Balance	(4)	(6)
Other Comprehensive Income (Loss), Net of Tax	2	1	1
Mississippi Power [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	(4)	(6)	(7)	(8)
Change in Accumulated OCI (loss) balances [Roll Forward]
Current period change	2	1	1
Gulf Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 1,389	1,355	1,309	1,235
Original maturities of temporary cash investments	90 days
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	$ 0
Current period change	1	1
Ending Balance	1	0
Other Comprehensive Income (Loss), Net of Tax	1	1	0
Gulf Power [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1	0	(1)	(1)
Change in Accumulated OCI (loss) balances [Roll Forward]
Current period change	1	1
Alabama Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 6,323	5,992	5,752	5,502
Original maturities of temporary cash investments	90 days
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	$ (32)
Current period change	2	(3)	(3)
Ending Balance	(30)	(32)
Other Comprehensive Income (Loss), Net of Tax	2	(3)	(3)
Alabama Power [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	(30)	(32)	(29)	(26)
Change in Accumulated OCI (loss) balances [Roll Forward]
Current period change	2	(3)	(3)
Georgia Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 11,356	10,719	10,421	9,591
Original maturities of temporary cash investments	90 days
Change in Accumulated OCI (loss) balances [Roll Forward]
Beginning Balance	$ (15)
Current period change	2	(7)	(3)
Ending Balance	(13)	(15)
Other Comprehensive Income (Loss), Net of Tax	2	(7)	(3)
Georgia Power [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	(13)	(15)	(8)	$ (5)
Change in Accumulated OCI (loss) balances [Roll Forward]
Current period change	$ 2	$ (7)	$ (3)
Wholesale Gas Services [Member] | Accounts Receivable [Member] | Credit Concentration Risk [Member] | Southern Company Gas [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of top counterparties | counterparty	20
Wholesale Services [Member] | Accounts Receivable [Member] | Credit Concentration Risk [Member] | Southern Company Gas [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Concentration risk (as percent)	46.00%
Accounts receivable	$ 205

Summary of Significant Accoun63

Summary of Significant Accounting Policies - Financial Instruments and Inventory at Lower of Cost or Market Adjustment (Details) - USD ($)	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Georgia Power [Member]
Inventory [Line Items]
Derivative collateral obligation to return cash	$ 0
Nicor Gas [Member]
Inventory [Line Items]
Excess of replacements or current costs over stated LIFO value	162,000,000
Inventory net	310,000,000
LIFO inventory amount	148,000,000
Southern Power [Member]
Inventory [Line Items]
Derivative collateral obligation to return cash	0
Alabama Power [Member]
Inventory [Line Items]
Derivative collateral obligation to return cash	0
Gulf Power [Member]
Inventory [Line Items]
Derivative collateral obligation to return cash	0
Successor [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves	1,000,000
Successor [Member] | Gas Marketing Services [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves	0
Successor [Member] | Wholesale Gas Services [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves	1,000,000
Successor [Member] | All Other [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves	$ 0
Predecessor [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves		$ 3,000,000	$ 23,000,000	$ 77,000,000
Predecessor [Member] | Gas Marketing Services [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves		0	3,000,000	4,000,000
Predecessor [Member] | Wholesale Gas Services [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves		3,000,000	19,000,000	73,000,000
Predecessor [Member] | All Other [Member] | Southern Company Gas [Member]
Inventory [Line Items]
Inventory valuation reserves		$ 0	$ 1,000,000	$ 0

Summary of Significant Accoun64

Summary of Significant Accounting Policies - Variable Interest Entity (Details) - Mississippi Power [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Variable Interest Entity, Consolidated, Carrying Amount, Assets	$ 20	$ 21
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	$ 24	$ 25

Retirement Benefits - Actuarial

Retirement Benefits - Actuarial Assumptions (Details)	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2017
Pension plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs			8.16%	8.20%	8.20%
Annual salary increase on net periodic benefit costs			4.37%	3.59%	3.59%
Discount rate, benefit obligation	4.40%		4.40%	4.67%
Annual salary increase, benefit obligation	4.37%		4.37%	4.46%
Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs			6.66%	6.97%	7.15%
Annual salary increase on net periodic benefit costs			4.37%	3.59%	3.59%
Discount rate, benefit obligation	4.23%		4.23%	4.51%
Annual salary increase, benefit obligation	4.37%		4.37%	4.46%
Employee benefit obligations | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.58%	4.17%	5.02%
Employee benefit obligations | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.38%	4.04%	4.85%
Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.88%	4.17%	5.02%
Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.66%	4.04%	4.85%
Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.98%	4.48%	5.02%
Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.85%	4.39%	4.85%
Southern Company Gas [Member]
Pension Plans and Postretirement Plans
Pension band increase, benefit obligation	2.00%		2.00%
Southern Company Gas [Member] | Scenario, Forecast [Member]
Pension Plans and Postretirement Plans
Pension band increase, benefit obligation						2.00%
Southern Company Gas [Member] | Successor [Member] | Pension plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs	7.75%
Annual salary increase on net periodic benefit costs	3.50%
Pension bad increase on net periodic benefit costs	2.00%
Discount rate, benefit obligation	4.39%		4.39%
Annual salary increase, benefit obligation	3.50%		3.50%
Pension band increase, benefit obligation	2.00%		2.00%
Southern Company Gas [Member] | Successor [Member] | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs	5.93%
Annual salary increase on net periodic benefit costs	3.50%
Discount rate, benefit obligation	4.15%		4.15%
Annual salary increase, benefit obligation	3.50%		3.50%
Southern Company Gas [Member] | Successor [Member] | Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs	3.21%
Southern Company Gas [Member] | Successor [Member] | Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs	2.84%
Southern Company Gas [Member] | Successor [Member] | Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs	4.07%
Southern Company Gas [Member] | Successor [Member] | Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs	3.96%
Southern Company Gas [Member] | Predecessor [Member] | Pension plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs		7.80%		7.80%	7.80%
Annual salary increase on net periodic benefit costs		3.70%		3.70%	3.70%
Pension bad increase on net periodic benefit costs		2.00%		2.00%	2.00%
Discount rate, benefit obligation				4.60%
Annual salary increase, benefit obligation				3.70%
Pension band increase, benefit obligation				2.00%
Southern Company Gas [Member] | Predecessor [Member] | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs		6.60%		7.80%	7.80%
Annual salary increase on net periodic benefit costs		3.70%		3.70%	3.70%
Discount rate, benefit obligation				4.40%
Annual salary increase, benefit obligation				3.70%
Southern Company Gas [Member] | Predecessor [Member] | Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs		4.00%		4.20%	5.00%
Southern Company Gas [Member] | Predecessor [Member] | Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs		3.60%		4.00%	4.70%
Southern Company Gas [Member] | Predecessor [Member] | Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs		4.80%		4.20%	5.00%
Southern Company Gas [Member] | Predecessor [Member] | Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs		4.70%		4.00%	4.70%
Alabama Power [Member] | Pension plans
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			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.44%		4.44%	4.67%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Alabama Power [Member] | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs			6.83%	7.17%	7.34%
Annual salary increase on net periodic benefit costs			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.27%		4.27%	4.51%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Alabama Power [Member] | Employee benefit obligations | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.67%	4.18%	5.02%
Alabama Power [Member] | Employee benefit obligations | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.51%	4.04%	4.86%
Alabama Power [Member] | Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.90%	4.18%	5.02%
Alabama Power [Member] | Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.69%	4.04%	4.86%
Alabama Power [Member] | Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			5.07%	4.49%	5.02%
Alabama Power [Member] | Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.96%	4.40%	4.86%
Georgia Power [Member] | Pension plans
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			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.40%		4.40%	4.65%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Georgia Power [Member] | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs			6.27%	6.48%	6.75%
Annual salary increase on net periodic benefit costs			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.23%		4.23%	4.49%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Georgia Power [Member] | Employee benefit obligations | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.65%	4.18%	5.02%
Georgia Power [Member] | Employee benefit obligations | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.49%	4.03%	4.85%
Georgia Power [Member] | Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.86%	4.18%	5.02%
Georgia Power [Member] | Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.67%	4.03%	4.85%
Georgia Power [Member] | Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			5.03%	4.49%	5.02%
Georgia Power [Member] | Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.88%	4.39%	4.85%
Gulf Power [Member] | Pension plans
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			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.46%		4.46%	4.71%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Gulf Power [Member] | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs			8.05%	8.07%	8.08%
Annual salary increase on net periodic benefit costs			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.25%		4.25%	4.51%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Gulf Power [Member] | Employee benefit obligations | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.71%	4.18%	5.02%
Gulf Power [Member] | Employee benefit obligations | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.51%	4.04%	4.86%
Gulf Power [Member] | Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.97%	4.18%	5.02%
Gulf Power [Member] | Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.68%	4.04%	4.86%
Gulf Power [Member] | Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			5.04%	4.48%	5.02%
Gulf Power [Member] | Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.88%	4.38%	4.86%
Mississippi Power [Member] | Pension plans
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			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.44%		4.44%	4.69%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Mississippi Power [Member] | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Long-term return on plan assets on net periodic benefit costs			7.07%	7.23%	7.30%
Annual salary increase on net periodic benefit costs			4.46%	3.59%	3.59%
Discount rate, benefit obligation	4.22%		4.22%	4.47%
Annual salary increase, benefit obligation	4.46%		4.46%	4.46%
Mississippi Power [Member] | Employee benefit obligations | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.69%	4.17%	5.01%
Mississippi Power [Member] | Employee benefit obligations | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.47%	4.03%	4.85%
Mississippi Power [Member] | Interest costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.97%	4.17%	5.01%
Mississippi Power [Member] | Interest costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			3.66%	4.03%	4.85%
Mississippi Power [Member] | Service costs | Pension plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			5.04%	4.49%	5.01%
Mississippi Power [Member] | Service costs | Other postretirement benefit plans
Pension Plans and Postretirement Plans
Discount rate on net periodic benefit costs			4.88%	4.38%	4.85%

Retirement Benefits - Schedule

Retirement Benefits - Schedule of Health Care Cost Trend Rates (Details)	12 Months Ended
	Dec. 31, 2016USD ($)
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Benefit obligation, 1 percent increase	$ 128,000,000
Benefit obligation, 1 percent decrease	110,000,000
Service and interest costs, 1 percent increase	4,000,000
Service and interest costs, 1 percent decrease	$ 3,000,000
Other postretirement benefit plans | Pre-65
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	6.50%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Other postretirement benefit plans | Post-65 medical
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	5.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Other postretirement benefit plans | Post-65 prescription
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	10.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Southern Company Gas [Member] | Other postretirement benefit plans | Pre-65
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	6.60%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,038
Southern Company Gas [Member] | Other postretirement benefit plans | Post-65 medical
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	8.40%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,038
Southern Company Gas [Member] | Other postretirement benefit plans | Post-65 prescription
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	8.40%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,038
Alabama Power [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Benefit obligation, 1 percent increase	$ 28,000,000
Benefit obligation, 1 percent decrease	24,000,000
Service and interest costs, 1 percent increase	1,000,000
Service and interest costs, 1 percent decrease	$ 1,000,000
Alabama Power [Member] | Other postretirement benefit plans | Pre-65
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	6.50%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Alabama Power [Member] | Other postretirement benefit plans | Post-65 medical
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	5.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Alabama Power [Member] | Other postretirement benefit plans | Post-65 prescription
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	10.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Georgia Power [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Benefit obligation, 1 percent increase	$ 55,000,000
Benefit obligation, 1 percent decrease	48,000,000
Service and interest costs, 1 percent increase	2,000,000
Service and interest costs, 1 percent decrease	$ 2,000,000
Georgia Power [Member] | Other postretirement benefit plans | Pre-65
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	6.50%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Georgia Power [Member] | Other postretirement benefit plans | Post-65 medical
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	5.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Georgia Power [Member] | Other postretirement benefit plans | Post-65 prescription
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	10.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Gulf Power [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Benefit obligation, 1 percent increase	$ 4,000,000
Benefit obligation, 1 percent decrease	3,000,000
Service and interest costs, 1 percent increase	0
Service and interest costs, 1 percent decrease	$ 0
Gulf Power [Member] | Other postretirement benefit plans | Pre-65
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	6.50%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Gulf Power [Member] | Other postretirement benefit plans | Post-65 medical
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	5.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Gulf Power [Member] | Other postretirement benefit plans | Post-65 prescription
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	10.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Mississippi Power [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Benefit obligation, 1 percent increase	$ 5,000,000
Benefit obligation, 1 percent decrease	4,000,000
Service and interest costs, 1 percent increase	0
Service and interest costs, 1 percent decrease	$ 0
Mississippi Power [Member] | Other postretirement benefit plans | Pre-65
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	6.50%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Mississippi Power [Member] | Other postretirement benefit plans | Post-65 medical
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	5.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Mississippi Power [Member] | Other postretirement benefit plans | Post-65 prescription
Defined Benefit Plan Disclosure [Line Items]
Initial Cost Trend Rate	10.00%
Ultimate Cost Trend Rate	4.50%
Year That Ultimate Rate Is Reached	2,025
Successor [Member] | Southern Company Gas [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Benefit obligation, 1 percent increase	$ 14,000,000
Benefit obligation, 1 percent decrease	12,000,000
Service and interest costs, 1 percent increase	0
Service and interest costs, 1 percent decrease	$ 0

Retirement Benefits - Changes i

Retirement Benefits - Changes in Projected Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions	Dec. 19, 2016	Sep. 12, 2016	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension plans
Change in benefit obligation
Benefit obligation at beginning of year				$ 10,542	$ 10,542	$ 10,909
Acquisitions					1,244	0
Service cost					262	257	$ 213
Interest cost					422	445	435
Benefits paid					(466)	(487)
Actuarial loss (gain)					381	(582)
Balance at end of year			$ 12,385		12,385	10,542	10,909
Change in plan assets
Fair value of plan assets at beginning of year				9,234	9,234	9,690
Acquisitions					837	0
Actual return (loss) on plan assets					902	(14)
Employer contributions	$ 900				1,076	45
Benefits paid					(466)	(487)
Fair value of plan assets at end of year			11,583		11,583	9,234	9,690
Accrued liability			(802)		(802)	(1,308)
Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year				1,989	1,989	1,986
Acquisitions					338	0
Service cost					22	23	21
Interest cost					76	78	79
Benefits paid					(119)	(102)
Actuarial loss (gain)					(16)	(38)
Plan amendments					0	34
Retiree drug subsidy					7	8
Balance at end of year			2,297		2,297	1,989	1,986
Change in plan assets
Fair value of plan assets at beginning of year				833	833	900
Acquisitions					100	0
Actual return (loss) on plan assets					58	(12)
Employer contributions					65	39
Benefits paid					(119)	(102)
Benefits paid, net of drug subsidy					(112)	(94)
Fair value of plan assets at end of year			944		944	833	900
Accrued liability			(1,353)		(1,353)	(1,156)
Georgia Power [Member] | Pension plans
Change in benefit obligation
Benefit obligation at beginning of year				3,615	3,615	3,781
Service cost					70	73	62
Interest cost					136	154	153
Benefits paid					(164)	(188)
Actuarial loss (gain)					143	(205)
Balance at end of year			3,800		3,800	3,615	3,781
Change in plan assets
Fair value of plan assets at beginning of year				3,196	3,196	3,383
Actual return (loss) on plan assets					288	(13)
Employer contributions	287				301	14
Benefits paid					(164)	(188)
Fair value of plan assets at end of year			3,621		3,621	3,196	3,383
Accrued liability			(179)		(179)	(419)
Georgia Power [Member] | Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year				854	854	864
Service cost					6	7	6
Interest cost					30	34	34
Benefits paid					(45)	(45)
Actuarial loss (gain)					(1)	(22)
Plan amendments					0	12
Retiree drug subsidy					3	4
Balance at end of year			847		847	854	864
Change in plan assets
Fair value of plan assets at beginning of year				358	358	395
Actual return (loss) on plan assets					21	(6)
Employer contributions					17	10
Benefits paid					(45)	(45)
Benefits paid, net of drug subsidy					(42)	(41)
Fair value of plan assets at end of year			354		354	358	395
Accrued liability			(493)		(493)	(496)
Alabama Power [Member] | Pension plans
Change in benefit obligation
Benefit obligation at beginning of year				2,506	2,506	2,592
Service cost					57	59	48
Interest cost					95	106	103
Benefits paid					(109)	(120)
Actuarial loss (gain)					114	(131)
Balance at end of year			2,663		2,663	2,506	2,592
Change in plan assets
Fair value of plan assets at beginning of year				2,279	2,279	2,396
Actual return (loss) on plan assets					206	(9)
Employer contributions	129				141	12
Benefits paid					(109)	(120)
Fair value of plan assets at end of year			2,517		2,517	2,279	2,396
Accrued liability			(146)		(146)	(227)
Alabama Power [Member] | Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year				505	505	503
Service cost					5	6	5
Interest cost					18	20	20
Benefits paid					(28)	(27)
Actuarial loss (gain)					(1)	(7)
Plan amendments					0	7
Retiree drug subsidy					2	3
Balance at end of year			501		501	505	503
Change in plan assets
Fair value of plan assets at beginning of year				363	363	392
Actual return (loss) on plan assets					23	(6)
Employer contributions					7	1
Benefits paid					(28)	(27)
Benefits paid, net of drug subsidy					(26)	(24)
Fair value of plan assets at end of year			367		367	363	392
Accrued liability			(134)		(134)	(142)
Gulf Power [Member]
Change in benefit obligation
Service cost					12	12	10
Interest cost					19	20	19
Gulf Power [Member] | Pension plans
Change in benefit obligation
Benefit obligation at beginning of year				480	480	491
Service cost					12	12
Interest cost					19	20
Benefits paid					(17)	(20)
Actuarial loss (gain)					23	(23)
Balance at end of year			517		517	480	491
Change in plan assets
Fair value of plan assets at beginning of year				420	420	435
Actual return (loss) on plan assets					39	4
Employer contributions	48				49	1
Benefits paid					(17)	(20)
Fair value of plan assets at end of year			491		491	420	435
Accrued liability			(26)		(26)	(60)
Gulf Power [Member] | Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year				81	81	78
Service cost					1	1	1
Interest cost					3	3	3
Benefits paid					(4)	(4)
Actuarial loss (gain)					2	(1)
Plan amendments					0	4
Balance at end of year			83		83	81	78
Change in plan assets
Fair value of plan assets at beginning of year				17	17	18
Actual return (loss) on plan assets					2	0
Employer contributions					3	3
Benefits paid					(4)	(4)
Benefits paid, net of drug subsidy					(4)	(4)
Fair value of plan assets at end of year			18		18	17	18
Accrued liability			(65)		(65)	(64)
Mississippi Power [Member]
Change in benefit obligation
Service cost					13	13	10
Interest cost					19	21	20
Mississippi Power [Member] | Pension plans
Change in benefit obligation
Benefit obligation at beginning of year				500	500	513
Service cost					13	13
Interest cost					19	21
Benefits paid					(20)	(22)
Actuarial loss (gain)					22	(25)
Balance at end of year			534		534	500	513
Change in plan assets
Fair value of plan assets at beginning of year				430	430	446
Actual return (loss) on plan assets					39	4
Employer contributions	$ 47				50	2
Benefits paid					(20)	(22)
Fair value of plan assets at end of year			499		499	430	446
Accrued liability			(35)		(35)	(70)
Mississippi Power [Member] | Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year				97	97	96
Service cost					1	1	1
Interest cost					3	4	4
Benefits paid					(6)	(5)
Actuarial loss (gain)					1	(1)
Plan amendments					0	1
Retiree drug subsidy					1	1
Balance at end of year			97		97	97	96
Change in plan assets
Fair value of plan assets at beginning of year				23	23	24
Actual return (loss) on plan assets					1	0
Employer contributions					4	3
Benefits paid					(6)	(5)
Benefits paid, net of drug subsidy					(5)	(4)
Fair value of plan assets at end of year			23		23	23	24
Accrued liability			(74)		(74)	(74)
Successor [Member] | Southern Company Gas [Member]
Change in plan assets
Employee contributions			1
Successor [Member] | Southern Company Gas [Member] | Pension plans
Change in benefit obligation
Benefit obligation at beginning of year			1,244
Service cost			15
Interest cost			20
Benefits paid			(31)
Actuarial loss (gain)			(115)
Balance at end of year			1,133	1,244	1,133
Change in plan assets
Fair value of plan assets at beginning of year			837
Actual return (loss) on plan assets			48
Employer contributions		$ 125	129
Benefits paid			(31)
Fair value of plan assets at end of year			983	837	983
Accrued liability			(150)		(150)
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year			338
Service cost			1
Interest cost			5
Benefits paid			(11)
Actuarial loss (gain)			(26)
Retiree drug subsidy			0
Balance at end of year			308	338	308
Change in plan assets
Fair value of plan assets at beginning of year			100
Actual return (loss) on plan assets			4
Employee contributions			1
Employer contributions			11
Benefits paid			(11)
Benefits paid, net of drug subsidy			(11)
Fair value of plan assets at end of year			105	100	105
Accrued liability			(203)		(203)
Predecessor [Member] | Southern Company Gas [Member]
Change in plan assets
Employee contributions				1		1
Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Change in benefit obligation
Benefit obligation at beginning of year			1,244	1,067	1,067	1,098
Service cost				13		28	24
Interest cost				21		45	47
Benefits paid				(26)		(49)
Actuarial loss (gain)				169		(55)
Balance at end of year				1,244		1,067	1,098
Change in plan assets
Fair value of plan assets at beginning of year			837	847	847	906
Actual return (loss) on plan assets				15		(12)
Employer contributions				1		2
Benefits paid				(26)		(49)
Fair value of plan assets at end of year				837		847	906
Accrued liability				(407)		(220)
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Change in benefit obligation
Benefit obligation at beginning of year			338	318	318	334
Service cost				1		2	2
Interest cost				5		13	15
Benefits paid				(11)		(20)
Actuarial loss (gain)				24		(13)
Retiree drug subsidy				0		1
Balance at end of year				338		318	334
Change in plan assets
Fair value of plan assets at beginning of year			$ 100	99	$ 99	99
Actual return (loss) on plan assets				1		1
Employee contributions				1		1
Employer contributions				10		17
Benefits paid				(11)		(20)
Benefits paid, net of drug subsidy				(11)		(20)
Fair value of plan assets at end of year				100		99	$ 99
Accrued liability				$ (238)		$ (219)

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized in Balance Sheets and Amounts in AOCI (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	$ 6,851		$ 6,851	$ 4,989
Other deferred charges and assets	1,395		1,395	737
Other current liabilities	(683)		(683)	(484)
Employee benefit obligations	(2,299)		(2,299)	(2,582)
Other regulatory liabilities, deferred	(258)		(258)	(254)
Accumulated OCI	(180)		(180)	(130)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net Regulatory Assets	5,866		5,866	5,564
Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	3,207		3,207	2,998
Other current liabilities	(53)		(53)	(46)
Employee benefit obligations	(749)		(749)	(1,262)
Other regulatory liabilities, deferred	(87)		(87)	0
Accumulated OCI	100		100	125
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	55		55	30
Net (Gain) Loss	3,165		3,165	3,093
Prior Service Cost, Estimated			12
Net (Gain) Loss, Estimated	162		162
Pension plans | Accumulated Other Comprehensive Income (Loss) [Member]
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	4		4	3
Net (Gain) Loss	96		96	122
Prior Service Cost, Estimated			1
Net (Gain) Loss, Estimated	7		7
Pension plans | Regulatory Assets
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	51		51	27
Net (Gain) Loss	3,069		3,069	2,971
Prior Service Cost, Estimated			11
Net (Gain) Loss, Estimated	155		155
Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	419		419	433
Other current liabilities	(4)		(4)	(4)
Employee benefit obligations	(1,349)		(1,349)	(1,152)
Other regulatory liabilities, deferred	(41)		(41)	(22)
Accumulated OCI	7		7	8
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	25		25	32
Net (Gain) Loss	360		360	387
Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) [Member]
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	0		0	0
Net (Gain) Loss	7		7	8
Other postretirement benefit plans | Regulatory Assets
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	25		25	32
Net (Gain) Loss	353		353	379
Prior Service Cost, Estimated			6
Net (Gain) Loss, Estimated	13		13
Alabama Power [Member]
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	1,157		1,157	1,114
Other deferred charges and assets	163		163	103
Other current liabilities	(76)		(76)	(93)
Employee benefit obligations	(300)		(300)	(388)
Other regulatory liabilities, deferred	(100)		(100)	(136)
Accumulated OCI	(30)		(30)	(32)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net Regulatory Assets	1,047		1,047	791
Alabama Power [Member] | Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	870		870	822
Other current liabilities	(12)		(12)	(11)
Employee benefit obligations	(134)		(134)	(216)
Alabama Power [Member] | Pension plans | Regulatory Assets
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	10		10	6
Net (Gain) Loss	860		860	816
Prior Service Cost, Estimated			3
Net (Gain) Loss, Estimated	42		42
Alabama Power [Member] | Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	86		86	95
Employee benefit obligations	(134)		(134)	(142)
Other regulatory liabilities, deferred	(10)		(10)	(13)
Alabama Power [Member] | Other postretirement benefit plans | Regulatory Assets
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	76		76	82
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	15		15	19
Net (Gain) Loss	61		61	63
Prior Service Cost, Estimated			4
Net (Gain) Loss, Estimated	1		1
Georgia Power [Member]
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	2,774		2,774	2,152
Other deferred charges and assets	417		417	173
Other current liabilities	(182)		(182)	(154)
Employee benefit obligations	(703)		(703)	(949)
Accumulated OCI	(13)		(13)	(15)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net Regulatory Assets	3,506		3,506	2,933
Georgia Power [Member] | Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	1,129		1,129	1,076
Other current liabilities	(14)		(14)	(13)
Employee benefit obligations	(165)		(165)	(406)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	17		17	8
Net (Gain) Loss	1,112		1,112	1,068
Prior Service Cost, Estimated			3
Net (Gain) Loss, Estimated	57		57
Georgia Power [Member] | Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	213		213	223
Employee benefit obligations	(493)		(493)	(496)
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		6	8
Net (Gain) Loss	207		207	215
Prior Service Cost, Estimated			1
Net (Gain) Loss, Estimated	8		8
Gulf Power [Member]
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	512		512	427
Other deferred charges and assets	21		21	37
Other current liabilities	(31)		(31)	(29)
Employee benefit obligations	(96)		(96)	(129)
Other regulatory liabilities, deferred	(47)		(47)	(47)
Accumulated OCI	1		1	0
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net Regulatory Assets	320		320	296
Gulf Power [Member] | Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	153		153	142
Other current liabilities	(1)		(1)	(1)
Employee benefit obligations	(25)		(25)	(59)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	3		3	2
Net (Gain) Loss	150		150	140
Prior Service Cost, Estimated			1
Net (Gain) Loss, Estimated	7		7
Gulf Power [Member] | Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	11		11	10
Other current liabilities	(1)		(1)	(1)
Employee benefit obligations	(64)		(64)	(63)
Other regulatory liabilities, deferred	(4)		(4)	(5)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net (Gain) Loss	(7)		(7)	(5)
Mississippi Power [Member]
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	518		518	525
Other deferred charges and assets	56		56	61
Other current liabilities	(19)		(19)	(41)
Employee benefit obligations	(115)		(115)	(153)
Other regulatory liabilities, deferred	(84)		(84)	(79)
Accumulated OCI	(4)		(4)	(6)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net Regulatory Assets	737		737	667
Mississippi Power [Member] | Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	154		154	144
Other current liabilities	(3)		(3)	(3)
Employee benefit obligations	(32)		(32)	(67)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	3		3	2
Net (Gain) Loss	151		151	142
Prior Service Cost, Estimated			1
Net (Gain) Loss, Estimated	7		7
Mississippi Power [Member] | Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	21		21	21
Employee benefit obligations	(74)		(74)	(74)
Other regulatory liabilities, deferred	(2)		(2)	(3)
Predecessor [Member] | Southern Company Gas [Member]
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred				670
Other deferred charges and assets				153
Other current liabilities				(162)
Employee benefit obligations				(515)
Other regulatory liabilities, deferred				(53)
Accumulated OCI				(186)
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				(987)
Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred				88
Other deferred charges and assets				78
Other current liabilities				(4)
Employee benefit obligations				(294)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost				(4)
Net (Gain) Loss				374
Prior Service Cost, Estimated		$ (1)		(2)	$ (2)
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Accumulated Other Comprehensive Income (Loss) [Member]
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost				(4)
Net (Gain) Loss				286
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Regulatory Assets
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
Net (Gain) Loss				88
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred				30
Employee benefit obligations				(219)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost				(15)
Net (Gain) Loss				81
Prior Service Cost, Estimated		$ 1		3	$ 3
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) [Member]
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost				0
Net (Gain) Loss				36
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Regulatory Assets
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost				(15)
Net (Gain) Loss				$ 45
Successor [Member] | Southern Company Gas [Member]
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	973		973
Other deferred charges and assets	170		170
Other current liabilities	(108)		(108)
Employee benefit obligations	(441)		(441)
Other regulatory liabilities, deferred	(51)		(51)
Accumulated OCI	26		26
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Net Regulatory Assets	(715)		(715)
Successor [Member] | Southern Company Gas [Member] | Pension plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	267		267
Other deferred charges and assets	58		58
Other current liabilities	(2)		(2)
Employee benefit obligations	(206)		(206)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	(2)		(2)
Net (Gain) Loss	226		226
Prior Service Cost, Estimated	0
Successor [Member] | Southern Company Gas [Member] | Pension plans | Accumulated Other Comprehensive Income (Loss) [Member]
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	0		0
Net (Gain) Loss	(43)		(43)
Successor [Member] | Southern Company Gas [Member] | Pension plans | Regulatory Assets
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)		(2)
Net (Gain) Loss	269		269
Prior Service Cost, Estimated			1
Net (Gain) Loss, Estimated	(21)		(21)
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Amounts recognized in the consolidated balance sheets related to company's pension plans
Other regulatory assets, deferred	52		52
Employee benefit obligations	(203)		(203)
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	(12)		(12)
Net (Gain) Loss	61		61
Prior Service Cost, Estimated	0
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) [Member]
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	0		0
Net (Gain) Loss	(3)		(3)
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Regulatory Assets
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization
Prior Service Cost	(12)		(12)
Net (Gain) Loss	$ 64		$ 64

Retirement Benefits - Component

Retirement Benefits - Components of Accumulated OCI and Changes in Regulatory Assets (Details) - USD ($)	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other postretirement benefit plans
Reclassification adjustments
Amortization of prior service costs			$ 21,000,000	$ 21,000,000	$ 6,000,000
Net periodic benefit cost			59,000,000	64,000,000	47,000,000
Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) [Member]
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		$ 8,000,000	8,000,000	8,000,000
Net (gain) loss			(1,000,000)	0
Change in prior service costs				0
Reclassification adjustments
Amortization of prior service costs			0	0
Amortization of net gain (loss)			0	0
Total reclassification adjustments			0	0
Net periodic benefit cost			(1,000,000)	0
Ending Balance	$ 7,000,000		7,000,000	8,000,000	8,000,000
Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		411,000,000	411,000,000	366,000,000
Net (gain) loss			(13,000,000)	33,000,000
Change in prior service costs				33,000,000
Reclassification adjustments
Amortization of prior service costs			(6,000,000)	(4,000,000)
Amortization of net gain (loss)			(14,000,000)	(17,000,000)
Total reclassification adjustments			(20,000,000)	(21,000,000)
Net periodic benefit cost			(33,000,000)	45,000,000
Ending Balance	378,000,000		378,000,000	411,000,000	366,000,000
Pension plans
Reclassification adjustments
Amortization of prior service costs			14,000,000	25,000,000	26,000,000
Net periodic benefit cost			66,000,000	218,000,000	139,000,000
Pension plans | Accumulated Other Comprehensive Income (Loss) [Member]
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		125,000,000	125,000,000	134,000,000
Net (gain) loss			(20,000,000)	1,000,000
Change in prior service costs			2,000,000
Reclassification adjustments
Amortization of prior service costs			(1,000,000)	(1,000,000)
Amortization of net gain (loss)			(6,000,000)	(9,000,000)
Total reclassification adjustments			(7,000,000)	(10,000,000)
Net periodic benefit cost			(25,000,000)	(9,000,000)
Ending Balance	100,000,000		100,000,000	125,000,000	134,000,000
Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		2,998,000,000	2,998,000,000	3,073,000,000
Net (gain) loss			243,000,000	155,000,000
Change in prior service costs			37,000,000
Reclassification adjustments
Amortization of prior service costs			(13,000,000)	(24,000,000)
Amortization of net gain (loss)			(145,000,000)	(206,000,000)
Total reclassification adjustments			(158,000,000)	(230,000,000)
Net periodic benefit cost			122,000,000	(75,000,000)
Ending Balance	3,120,000,000		3,120,000,000	2,998,000,000	3,073,000,000
Mississippi Power [Member]
Reclassification adjustments
Amortization of prior service costs			1,000,000	1,000,000	1,000,000
Net periodic benefit cost			5,000,000	12,000,000	7,000,000
Mississippi Power [Member] | Other postretirement benefit plans
Reclassification adjustments
Amortization of prior service costs			1,000,000	1,000,000	0
Net periodic benefit cost			4,000,000	4,000,000	3,000,000
Mississippi Power [Member] | Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		18,000,000	18,000,000	16,000,000
Net (gain) loss			2,000,000	0
Change in prior service costs			0	3,000,000
Reclassification adjustments
Amortization of net gain (loss)			(1,000,000)	(1,000,000)
Total reclassification adjustments			(1,000,000)	(1,000,000)
Net periodic benefit cost			1,000,000	2,000,000
Ending Balance	19,000,000		19,000,000	18,000,000	16,000,000
Mississippi Power [Member] | Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		144,000,000	144,000,000	151,000,000
Net (gain) loss			16,000,000	4,000,000
Change in prior service costs			2,000,000	0
Reclassification adjustments
Amortization of prior service costs			(1,000,000)	(1,000,000)
Amortization of net gain (loss)			(7,000,000)	(10,000,000)
Total reclassification adjustments			(8,000,000)	(11,000,000)
Net periodic benefit cost			10,000,000	(7,000,000)
Ending Balance	154,000,000		154,000,000	144,000,000	151,000,000
Georgia Power [Member] | Other postretirement benefit plans
Reclassification adjustments
Amortization of prior service costs			10,000,000	11,000,000	2,000,000
Net periodic benefit cost			24,000,000	28,000,000	17,000,000
Georgia Power [Member] | Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		223,000,000	223,000,000	213,000,000
Net (gain) loss			0	9,000,000
Change in prior service costs			0	12,000,000
Reclassification adjustments
Amortization of prior service costs			(1,000,000)	0
Amortization of net gain (loss)			(9,000,000)	(11,000,000)
Total reclassification adjustments			(10,000,000)	(11,000,000)
Net periodic benefit cost			(10,000,000)	10,000,000
Ending Balance	213,000,000		213,000,000	223,000,000	213,000,000
Georgia Power [Member] | Pension plans
Reclassification adjustments
Amortization of prior service costs			5,000,000	9,000,000	10,000,000
Net periodic benefit cost			8,000,000	61,000,000	38,000,000
Georgia Power [Member] | Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		1,076,000,000	1,076,000,000	1,102,000,000
Net (gain) loss			99,000,000	59,000,000
Change in prior service costs			14,000,000	0
Reclassification adjustments
Amortization of prior service costs			(5,000,000)	(9,000,000)
Amortization of net gain (loss)			(55,000,000)	(76,000,000)
Total reclassification adjustments			(60,000,000)	(85,000,000)
Net periodic benefit cost			53,000,000	(26,000,000)
Ending Balance	1,129,000,000		1,129,000,000	1,076,000,000	1,102,000,000
Alabama Power [Member] | Other postretirement benefit plans
Reclassification adjustments
Amortization of prior service costs			6,000,000	5,000,000	4,000,000
Net periodic benefit cost			4,000,000	5,000,000	4,000,000
Alabama Power [Member] | Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		82,000,000	82,000,000	54,000,000
Net (gain) loss			0	25,000,000
Change in prior service costs			0	8,000,000
Reclassification adjustments
Amortization of prior service costs			(4,000,000)	(3,000,000)
Amortization of net gain (loss)			(2,000,000)	(2,000,000)
Total reclassification adjustments			(6,000,000)	(5,000,000)
Net periodic benefit cost			(6,000,000)	28,000,000
Ending Balance	76,000,000		76,000,000	82,000,000	54,000,000
Alabama Power [Member] | Pension plans
Reclassification adjustments
Amortization of prior service costs			3,000,000	6,000,000	7,000,000
Net periodic benefit cost			11,000,000	48,000,000	21,000,000
Alabama Power [Member] | Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		822,000,000	822,000,000	827,000,000
Net (gain) loss			84,000,000	56,000,000
Change in prior service costs			7,000,000	0
Reclassification adjustments
Amortization of prior service costs			(3,000,000)	(6,000,000)
Amortization of net gain (loss)			(40,000,000)	(55,000,000)
Total reclassification adjustments			(43,000,000)	(61,000,000)
Net periodic benefit cost			48,000,000	(5,000,000)
Ending Balance	870,000,000		870,000,000	822,000,000	827,000,000
Gulf Power [Member]
Reclassification adjustments
Amortization of prior service costs			1,000,000	1,000,000	1,000,000
Net periodic benefit cost			4,000,000	10,000,000	7,000,000
Gulf Power [Member] | Other postretirement benefit plans
Reclassification adjustments
Net periodic benefit cost			3,000,000	3,000,000	3,000,000
Gulf Power [Member] | Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		5,000,000	5,000,000	2,000,000
Net (gain) loss			2,000,000	1,000,000
Change in prior service costs			0	2,000,000
Reclassification adjustments
Net periodic benefit cost			2,000,000	3,000,000
Ending Balance	7,000,000		7,000,000	5,000,000	2,000,000
Gulf Power [Member] | Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance		142,000,000	142,000,000	146,000,000
Net (gain) loss			16,000,000	6,000,000
Change in prior service costs			2,000,000	0
Reclassification adjustments
Amortization of prior service costs			(1,000,000)	(1,000,000)
Amortization of net gain (loss)			(6,000,000)	(9,000,000)
Total reclassification adjustments			(7,000,000)	(10,000,000)
Net periodic benefit cost			11,000,000	(4,000,000)
Ending Balance	153,000,000		153,000,000	142,000,000	146,000,000
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Reclassification adjustments
Net periodic benefit cost	5,000,000
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) [Member]
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	0
Net (gain) loss	(3,000,000)
Reclassification adjustments
Amortization of prior service costs	0
Amortization of net gain (loss)	0
Total reclassification adjustments	0
Net periodic benefit cost	(3,000,000)
Ending Balance	(3,000,000)	0	(3,000,000)
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	77,000,000
Net (gain) loss	(23,000,000)
Reclassification adjustments
Amortization of prior service costs	1,000,000
Amortization of net gain (loss)	(3,000,000)
Total reclassification adjustments	(2,000,000)
Net periodic benefit cost	(25,000,000)
Ending Balance	52,000,000	77,000,000	52,000,000
Successor [Member] | Southern Company Gas [Member] | Pension plans
Reclassification adjustments
Net periodic benefit cost	13,000,000
Successor [Member] | Southern Company Gas [Member] | Pension plans | Accumulated Other Comprehensive Income (Loss) [Member]
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	0
Net (gain) loss	(43,000,000)
Reclassification adjustments
Amortization of prior service costs	0
Amortization of net gain (loss)	0
Total reclassification adjustments	0
Net periodic benefit cost	(43,000,000)
Ending Balance	(43,000,000)	0	(43,000,000)
Successor [Member] | Southern Company Gas [Member] | Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	368,000,000
Net (gain) loss	(87,000,000)
Reclassification adjustments
Amortization of prior service costs	1,000,000
Amortization of net gain (loss)	(15,000,000)
Total reclassification adjustments	(14,000,000)
Net periodic benefit cost	(101,000,000)
Ending Balance	267,000,000	368,000,000	267,000,000
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Reclassification adjustments
Net periodic benefit cost		4,000,000		11,000,000	13,000,000
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Accumulated Other Comprehensive Income (Loss) [Member]
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	35,000,000	36,000,000	36,000,000	36,000,000
Net (gain) loss				2,000,000
Reclassification adjustments
Amortization of prior service costs		0		0
Amortization of net gain (loss)		(1,000,000)		(2,000,000)
Total reclassification adjustments		(1,000,000)		(2,000,000)
Net periodic benefit cost		(1,000,000)		0
Ending Balance		35,000,000		36,000,000	36,000,000
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	30,000,000	30,000,000	30,000,000	39,000,000
Net (gain) loss				(8,000,000)
Reclassification adjustments
Amortization of prior service costs		1,000,000		2,000,000
Amortization of net gain (loss)		(1,000,000)		(3,000,000)
Total reclassification adjustments		0		(1,000,000)
Net periodic benefit cost		0		(9,000,000)
Ending Balance		30,000,000		30,000,000	39,000,000
Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Reclassification adjustments
Net periodic benefit cost		13,000,000		37,000,000	26,000,000
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Accumulated Other Comprehensive Income (Loss) [Member]
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	274,000,000	282,000,000	282,000,000	301,000,000
Net (gain) loss				0
Reclassification adjustments
Amortization of prior service costs		1,000,000		2,000,000
Amortization of net gain (loss)		(9,000,000)		(21,000,000)
Total reclassification adjustments		(8,000,000)		(19,000,000)
Net periodic benefit cost		(8,000,000)		(19,000,000)
Ending Balance		274,000,000		282,000,000	301,000,000
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Regulatory Assets
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]
Beginning Balance	$ 84,000,000	88,000,000	$ 88,000,000	76,000,000
Net (gain) loss				22,000,000
Reclassification adjustments
Amortization of prior service costs		0		0
Amortization of net gain (loss)		(4,000,000)		(10,000,000)
Total reclassification adjustments		(4,000,000)		(10,000,000)
Net periodic benefit cost		(4,000,000)		12,000,000
Ending Balance		$ 84,000,000		$ 88,000,000	$ 76,000,000

Retirement Benefits - Compone70

Retirement Benefits - Components of Net Periodic Benefit Cost and Estimated Future Benefit Payments (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)				100.00%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%	100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 22	$ 23	$ 21
Interest cost			76	78	79
Expected return on plan assets			(60)	(58)	(59)
Net amortization			21	21	6
Net periodic benefit cost			59	$ 64	47
Benefit Payments
Benefit Payments, 2017	$ 145		145
Benefit Payments, 2018	150		150
Benefit Payments, 2019	155		155
Benefit Payments, 2020	159		159
Benefit Payments, 2021	162		162
Benefit Payments, 2022 to 2026	823		823
Subsidy Receipts
Subsidy Receipts, 2017	(10)		(10)
Subsidy Receipts, 2018	(11)		(11)
Subsidy Receipts, 2019	(12)		(12)
Subsidy Receipts, 2020	(13)		(13)
Subsidy Receipts, 2021	(14)		(14)
Subsidy Receipts, 2022 to 2026	(73)		(73)
Benefit Payments and Subsidy Receipts, Total
Benefit Payments and Subsidy Receipts, 2017	135		135
Benefit Payments and Subsidy Receipts, 2018	139		139
Benefit Payments and Subsidy Receipts, 2019	143		143
Benefit Payments and Subsidy Receipts, 2020	146		146
Benefit Payments and Subsidy Receipts, 2021	148		148
Benefit Payments and Subsidy Receipts, 2022 to 2026	750		750
Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)				100.00%
Actual plan asset allocations (as percent)				100.00%
Components of net periodic
Service cost			262	$ 257	213
Interest cost			422	445	435
Expected return on plan assets			(782)	(724)	(645)
Amortization prior service costs			12
Recognized net (gain) loss			150	215	110
Net amortization			14	25	26
Net periodic benefit cost			66	$ 218	139
Benefit Payments
Benefit Payments, 2017	571		571
Benefit Payments, 2018	593		593
Benefit Payments, 2019	620		620
Benefit Payments, 2020	646		646
Benefit Payments, 2021	666		666
Benefit Payments, 2022 to 2026	$ 3,673		$ 3,673
Alabama Power [Member]
Components of net periodic
Amortization of regulatory assets					123
Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 5	$ 6	5
Interest cost			18	20	20
Expected return on plan assets			(25)	(26)	(25)
Net amortization			6	5	4
Net periodic benefit cost			4	$ 5	4
Benefit Payments
Benefit Payments, 2017	$ 32		32
Benefit Payments, 2018	33		33
Benefit Payments, 2019	34		34
Benefit Payments, 2020	35		35
Benefit Payments, 2021	36		36
Benefit Payments, 2022 to 2026	183		183
Subsidy Receipts
Subsidy Receipts, 2017	(3)		(3)
Subsidy Receipts, 2018	(3)		(3)
Subsidy Receipts, 2019	(4)		(4)
Subsidy Receipts, 2020	(4)		(4)
Subsidy Receipts, 2021	(4)		(4)
Subsidy Receipts, 2022 to 2026	(22)		(22)
Benefit Payments and Subsidy Receipts, Total
Benefit Payments and Subsidy Receipts, 2017	29		29
Benefit Payments and Subsidy Receipts, 2018	30		30
Benefit Payments and Subsidy Receipts, 2019	30		30
Benefit Payments and Subsidy Receipts, 2020	31		31
Benefit Payments and Subsidy Receipts, 2021	32		32
Benefit Payments and Subsidy Receipts, 2022 to 2026	$ 161		$ 161
Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 57	$ 59	48
Interest cost			95	106	103
Expected return on plan assets			(184)	(178)	(168)
Recognized net (gain) loss			40	55	31
Net amortization			3	6	7
Net periodic benefit cost			11	$ 48	21
Benefit Payments
Benefit Payments, 2017	$ 122		122
Benefit Payments, 2018	127		127
Benefit Payments, 2019	132		132
Benefit Payments, 2020	137		137
Benefit Payments, 2021	142		142
Benefit Payments, 2022 to 2026	$ 777		$ 777
Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 6	$ 7	6
Interest cost			30	34	34
Expected return on plan assets			(22)	(24)	(25)
Amortization prior service costs			1
Net amortization			10	11	2
Net periodic benefit cost			24	$ 28	17
Benefit Payments
Benefit Payments, 2017	$ 54		54
Benefit Payments, 2018	56		56
Benefit Payments, 2019	58		58
Benefit Payments, 2020	59		59
Benefit Payments, 2021	60		60
Benefit Payments, 2022 to 2026	303		303
Subsidy Receipts
Subsidy Receipts, 2017	(4)		(4)
Subsidy Receipts, 2018	(5)		(5)
Subsidy Receipts, 2019	(5)		(5)
Subsidy Receipts, 2020	(5)		(5)
Subsidy Receipts, 2021	(6)		(6)
Subsidy Receipts, 2022 to 2026	(32)		(32)
Benefit Payments and Subsidy Receipts, Total
Benefit Payments and Subsidy Receipts, 2017	50		50
Benefit Payments and Subsidy Receipts, 2018	51		51
Benefit Payments and Subsidy Receipts, 2019	53		53
Benefit Payments and Subsidy Receipts, 2020	54		54
Benefit Payments and Subsidy Receipts, 2021	54		54
Benefit Payments and Subsidy Receipts, 2022 to 2026	$ 271		$ 271
Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 70	$ 73	62
Interest cost			136	154	153
Expected return on plan assets			(258)	(251)	(228)
Amortization prior service costs			3
Recognized net (gain) loss			55	76	41
Net amortization			5	9	10
Net periodic benefit cost			8	61	38
Benefit Payments
Benefit Payments, 2017	$ 184		184
Benefit Payments, 2018	190		190
Benefit Payments, 2019	196		196
Benefit Payments, 2020	202		202
Benefit Payments, 2021	206		206
Benefit Payments, 2022 to 2026	$ 1,126		1,126
Gulf Power [Member]
Components of net periodic
Service cost			12	12	10
Interest cost			19	20	19
Expected return on plan assets			(34)	(32)	(28)
Recognized net (gain) loss			6	9	5
Net amortization			1	1	1
Net periodic benefit cost			$ 4	$ 10	7
Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 1	$ 1	1
Interest cost			3	3	3
Expected return on plan assets			(1)	(1)	(1)
Net periodic benefit cost			3	$ 3	3
Benefit Payments
Benefit Payments, 2017	$ 5		5
Benefit Payments, 2018	5		5
Benefit Payments, 2019	6		6
Benefit Payments, 2020	6		6
Benefit Payments, 2021	6		6
Benefit Payments, 2022 to 2026	30		30
Subsidy Receipts
Subsidy Receipts, 2017	0		0
Subsidy Receipts, 2018	0		0
Subsidy Receipts, 2019	(1)		(1)
Subsidy Receipts, 2020	(1)		(1)
Subsidy Receipts, 2021	(1)		(1)
Subsidy Receipts, 2022 to 2026	(3)		(3)
Benefit Payments and Subsidy Receipts, Total
Benefit Payments and Subsidy Receipts, 2017	5		5
Benefit Payments and Subsidy Receipts, 2018	5		5
Benefit Payments and Subsidy Receipts, 2019	5		5
Benefit Payments and Subsidy Receipts, 2020	5		5
Benefit Payments and Subsidy Receipts, 2021	5		5
Benefit Payments and Subsidy Receipts, 2022 to 2026	$ 27		$ 27
Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 12	$ 12
Interest cost			19	20
Amortization prior service costs			1
Benefit Payments
Benefit Payments, 2017	$ 20		20
Benefit Payments, 2018	22		22
Benefit Payments, 2019	23		23
Benefit Payments, 2020	24		24
Benefit Payments, 2021	26		26
Benefit Payments, 2022 to 2026	$ 149		149
Mississippi Power [Member]
Components of net periodic
Service cost			13	13	10
Interest cost			19	21	20
Expected return on plan assets			(35)	(33)	(29)
Recognized net (gain) loss			7	10	5
Net amortization			1	1	1
Net periodic benefit cost			$ 5	$ 12	7
Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 1	$ 1	1
Interest cost			3	4	4
Expected return on plan assets			(1)	(2)	(2)
Net amortization			1	1	0
Net periodic benefit cost			4	$ 4	3
Benefit Payments
Benefit Payments, 2017	$ 6		6
Benefit Payments, 2018	6		6
Benefit Payments, 2019	7		7
Benefit Payments, 2020	7		7
Benefit Payments, 2021	7		7
Benefit Payments, 2022 to 2026	36		36
Subsidy Receipts
Subsidy Receipts, 2017	(1)		(1)
Subsidy Receipts, 2018	(1)		(1)
Subsidy Receipts, 2019	(1)		(1)
Subsidy Receipts, 2020	(1)		(1)
Subsidy Receipts, 2021	(1)		(1)
Subsidy Receipts, 2022 to 2026	(1)		(1)
Benefit Payments and Subsidy Receipts, Total
Benefit Payments and Subsidy Receipts, 2017	5		5
Benefit Payments and Subsidy Receipts, 2018	5		5
Benefit Payments and Subsidy Receipts, 2019	6		6
Benefit Payments and Subsidy Receipts, 2020	6		6
Benefit Payments and Subsidy Receipts, 2021	6		6
Benefit Payments and Subsidy Receipts, 2022 to 2026	$ 35		$ 35
Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			100.00%
Actual plan asset allocations (as percent)	100.00%		100.00%	100.00%
Components of net periodic
Service cost			$ 13	$ 13
Interest cost			19	$ 21
Amortization prior service costs			1
Benefit Payments
Benefit Payments, 2017	$ 22		22
Benefit Payments, 2018	23		23
Benefit Payments, 2019	24		24
Benefit Payments, 2020	26		26
Benefit Payments, 2021	27		27
Benefit Payments, 2022 to 2026	154		154
Successor [Member] | Southern Company Gas [Member] | Other Postretirement Benefit Plan [Member]
Components of net periodic
Service cost	1
Interest cost	5
Expected return on plan assets	(3)
Amortization of regulatory assets	2
Amortization prior service costs	0
Amortization net gain (loss)	0
Net periodic benefit cost	5
Benefit Payments
Benefit Payments, 2017	20		20
Benefit Payments, 2018	20		20
Benefit Payments, 2019	21		21
Benefit Payments, 2020	22		22
Benefit Payments, 2021	22		22
Benefit Payments, 2022 to 2026	111		111
Successor [Member] | Southern Company Gas [Member] | Pension plans
Components of net periodic
Service cost	15
Interest cost	20
Expected return on plan assets	(35)
Amortization of regulatory assets	13
Amortization prior service costs	0
Amortization net gain (loss)	0
Net periodic benefit cost	13
Benefit Payments
Benefit Payments, 2017	71		71
Benefit Payments, 2018	72		72
Benefit Payments, 2019	73		73
Benefit Payments, 2020	74		74
Benefit Payments, 2021	74		74
Benefit Payments, 2022 to 2026	$ 363		$ 363
Predecessor [Member] | Southern Company Gas [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				100.00%
Components of net periodic
Service cost		$ 1		$ 2	2
Interest cost		5		13	15
Expected return on plan assets		(3)		(7)	(7)
Amortization of regulatory assets		0		0	0
Amortization prior service costs		1		3	3
Amortization net gain (loss)		2		6	6
Net periodic benefit cost		4		$ 11	13
Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				100.00%
Components of net periodic
Service cost		13		$ 28	24
Interest cost		21		45	47
Expected return on plan assets		(33)		(65)	(65)
Amortization of regulatory assets		0		0	0
Amortization prior service costs		(1)		(2)	(2)
Amortization net gain (loss)		13		31	22
Net periodic benefit cost		$ 13		$ 37	$ 26
Fixed income | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			29.00%	28.00%
Actual plan asset allocations (as percent)	31.00%		31.00%	30.00%
Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			23.00%	23.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	23.00%
Fixed income | Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			23.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	23.00%
Fixed income | Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			23.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	23.00%
Fixed income | Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			23.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	23.00%
Fixed income | Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			38.00%
Actual plan asset allocations (as percent)	43.00%		43.00%	38.00%
Fixed income | Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			23.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	23.00%
Fixed income | Successor [Member] | Southern Company Gas [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			24.00%
Actual plan asset allocations (as percent)	23.00%		23.00%
Fixed income | Predecessor [Member] | Southern Company Gas [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				24.00%
Fixed income | Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				29.00%
Domestic equity | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			39.00%	42.00%
Actual plan asset allocations (as percent)	40.00%		40.00%	38.00%
Domestic equity | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			26.00%	26.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	30.00%
Domestic equity | Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			46.00%
Actual plan asset allocations (as percent)	44.00%		44.00%	45.00%
Domestic equity | Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			26.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	30.00%
Domestic equity | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			36.00%
Actual plan asset allocations (as percent)	35.00%		35.00%	34.00%
Domestic equity | Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			26.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	30.00%
Domestic equity | Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%
Actual plan asset allocations (as percent)	28.00%		28.00%	29.00%
Domestic equity | Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			26.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	30.00%
Domestic equity | Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			21.00%
Actual plan asset allocations (as percent)	23.00%		23.00%	24.00%
Domestic equity | Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			26.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	30.00%
Special situations | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			1.00%	1.00%
Actual plan asset allocations (as percent)	1.00%		1.00%	1.00%
Special situations | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%	3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Special situations | Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			1.00%
Actual plan asset allocations (as percent)	1.00%		1.00%	1.00%
Special situations | Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Special situations | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			1.00%
Actual plan asset allocations (as percent)	1.00%		1.00%	0.00%
Special situations | Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Special situations | Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Special situations | Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Special situations | Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Special situations | Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
International equity | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			23.00%	21.00%
Actual plan asset allocations (as percent)	21.00%		21.00%	23.00%
International equity | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%	25.00%
Actual plan asset allocations (as percent)	22.00%		22.00%	23.00%
International equity | Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			22.00%
Actual plan asset allocations (as percent)	20.00%		20.00%	20.00%
International equity | Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%
Actual plan asset allocations (as percent)	22.00%		22.00%	23.00%
International equity | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			24.00%
Actual plan asset allocations (as percent)	24.00%		24.00%	27.00%
International equity | Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%
Actual plan asset allocations (as percent)	22.00%		22.00%	23.00%
International equity | Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			24.00%
Actual plan asset allocations (as percent)	21.00%		21.00%	22.00%
International equity | Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%
Actual plan asset allocations (as percent)	22.00%		22.00%	23.00%
International equity | Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			20.00%
Actual plan asset allocations (as percent)	18.00%		18.00%	18.00%
International equity | Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%
Actual plan asset allocations (as percent)	22.00%		22.00%	23.00%
Domestic Fixed Income Investments [Member] | Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			24.00%
Actual plan asset allocations (as percent)	29.00%		29.00%	27.00%
Domestic Fixed Income Investments [Member] | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			33.00%
Actual plan asset allocations (as percent)	35.00%		35.00%	25.00%
Domestic Fixed Income Investments [Member] | Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			25.00%
Actual plan asset allocations (as percent)	31.00%		31.00%	25.00%
Global Fixed Income Investments [Member] | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)
Actual plan asset allocations (as percent)				8.00%
Real Estate Investment [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			5.00%	5.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Real Estate Investment [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			14.00%	14.00%
Actual plan asset allocations (as percent)	13.00%		13.00%	16.00%
Real Estate Investment [Member] | Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			4.00%
Actual plan asset allocations (as percent)	4.00%		4.00%	5.00%
Real Estate Investment [Member] | Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			14.00%
Actual plan asset allocations (as percent)	13.00%		13.00%	16.00%
Real Estate Investment [Member] | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			4.00%
Actual plan asset allocations (as percent)	4.00%		4.00%	4.00%
Real Estate Investment [Member] | Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			14.00%
Actual plan asset allocations (as percent)	13.00%		13.00%	16.00%
Real Estate Investment [Member] | Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			14.00%
Actual plan asset allocations (as percent)	13.00%		13.00%	16.00%
Real Estate Investment [Member] | Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			14.00%
Actual plan asset allocations (as percent)	13.00%		13.00%	16.00%
Real Estate Investment [Member] | Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			11.00%
Actual plan asset allocations (as percent)	10.00%		10.00%	13.00%
Real Estate Investment [Member] | Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			14.00%
Actual plan asset allocations (as percent)	13.00%		13.00%	16.00%
Private Equity Funds [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%	3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Private Equity Funds [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			9.00%	9.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Private Equity Funds [Member] | Alabama Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			3.00%
Actual plan asset allocations (as percent)	2.00%		2.00%	2.00%
Private Equity Funds [Member] | Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			9.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Private Equity Funds [Member] | Georgia Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			2.00%
Actual plan asset allocations (as percent)	1.00%		1.00%	2.00%
Private Equity Funds [Member] | Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			9.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Private Equity Funds [Member] | Gulf Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			9.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Private Equity Funds [Member] | Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			9.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Private Equity Funds [Member] | Mississippi Power [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			7.00%
Actual plan asset allocations (as percent)	4.00%		4.00%	5.00%
Private Equity Funds [Member] | Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)			9.00%
Actual plan asset allocations (as percent)	5.00%		5.00%	6.00%
Private Equity Funds [Member] | Predecessor [Member] | Southern Company Gas [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				0.00%
Private Equity Funds [Member] | Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				2.00%

Retirement Benefits - Fair Valu

Retirement Benefits - Fair Values of Pension Plan and Other Postretirement Benefit Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2016	Dec. 31, 2014
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)		100.00%
Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 11,583	$ 9,234		$ 9,690
Assets Fair Value
Fair Value, Plan Assets	10,583	9,083
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	1,881	1,881
Liabilities Fair Value
Fair Value, Plan Liabilities		(1)
Fair Value, Plan Assets and Liabilities		$ 9,082
Target plan asset allocations (as percent)		100.00%
Actual plan asset allocations (as percent)		100.00%
Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 2,937	$ 2,313
Liabilities Fair Value
Target plan asset allocations (as percent)	26.00%	26.00%
Actual plan asset allocations (as percent)	29.00%	30.00%
Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 2,341	$ 2,152
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%	25.00%
Actual plan asset allocations (as percent)	22.00%	23.00%
Pension plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	23.00%	23.00%
Actual plan asset allocations (as percent)	29.00%	23.00%
Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 588	$ 454
Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	13	199
Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	991	1,140
Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	524	500
Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	998	145
Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	1,462	1,484
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 1,152	$ 1,185
Liabilities Fair Value
Target plan asset allocations (as percent)	14.00%	14.00%
Actual plan asset allocations (as percent)	13.00%	16.00%
Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 180	$ 160
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 180	$ 160
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 549	$ 536
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 549	$ 536
Liabilities Fair Value
Target plan asset allocations (as percent)	9.00%	9.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 944	$ 833		900
Assets Fair Value
Fair Value, Plan Assets	838	834
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 57	$ 63
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 146	$ 158
Liabilities Fair Value
Target plan asset allocations (as percent)	39.00%	42.00%
Actual plan asset allocations (as percent)	40.00%	38.00%
Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 98	$ 103
Liabilities Fair Value
Target plan asset allocations (as percent)	23.00%	21.00%
Actual plan asset allocations (as percent)	21.00%	23.00%
Other postretirement benefit plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	29.00%	28.00%
Actual plan asset allocations (as percent)	31.00%	30.00%
Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 24	$ 22
Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets		7
Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	30	38
Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	49	42
Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	41	20
Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	382	370
Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	46	51
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 35	$ 40
Liabilities Fair Value
Target plan asset allocations (as percent)	5.00%	5.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 5	$ 5
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 5	$ 5
Liabilities Fair Value
Target plan asset allocations (as percent)	1.00%	1.00%
Actual plan asset allocations (as percent)	1.00%	1.00%
Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 17	$ 18
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 17	$ 18
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	$ 4,547	$ 3,121
Liabilities Fair Value
Fair Value, Plan Liabilities		(1)
Fair Value, Plan Assets and Liabilities		3,120
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	2,010	1,632
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	1,231	1,190
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	996	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	310	299
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	207	168
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	118	106
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	37	40
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets		0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	41	11
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	11	11
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	4,155	4,081
Liabilities Fair Value
Fair Value, Plan Liabilities		0
Fair Value, Plan Assets and Liabilities		4,081
Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	927	681
Significant Other Observable Inputs (Level 2) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	1,110	962
Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	588	454
Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	13	199
Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	991	1,140
Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	524	500
Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	2	145
Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	574	603
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	28	52
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	61	63
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	24	22
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets		7
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	30	38
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	49	42
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	9
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	382	370
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Liabilities Fair Value
Fair Value, Plan Liabilities		0
Fair Value, Plan Assets and Liabilities		0
Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets		0
Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets		0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,517	2,279		2,396
Assets Fair Value
Fair Value, Plan Assets	2,513	2,241
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 447	$ 458
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Alabama Power [Member] | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 697	$ 571
Liabilities Fair Value
Target plan asset allocations (as percent)	26.00%
Actual plan asset allocations (as percent)	29.00%	30.00%
Alabama Power [Member] | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 556	$ 538
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%
Actual plan asset allocations (as percent)	22.00%	23.00%
Alabama Power [Member] | Pension plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	23.00%
Actual plan asset allocations (as percent)	29.00%	23.00%
Alabama Power [Member] | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 140	$ 112
Alabama Power [Member] | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	3	49
Alabama Power [Member] | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	235	280
Alabama Power [Member] | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	124	123
Alabama Power [Member] | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	237	36
Alabama Power [Member] | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	348	375
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 274	$ 301
Liabilities Fair Value
Target plan asset allocations (as percent)	14.00%
Actual plan asset allocations (as percent)	13.00%	16.00%
Alabama Power [Member] | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 43
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 43
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Alabama Power [Member] | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 130	$ 157
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 130	$ 157
Liabilities Fair Value
Target plan asset allocations (as percent)	9.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Alabama Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 367	$ 363		392
Assets Fair Value
Fair Value, Plan Assets	366	361
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 20	$ 21
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Alabama Power [Member] | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 61	$ 65
Liabilities Fair Value
Target plan asset allocations (as percent)	46.00%
Actual plan asset allocations (as percent)	44.00%	45.00%
Alabama Power [Member] | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 25	$ 26
Liabilities Fair Value
Target plan asset allocations (as percent)	22.00%
Actual plan asset allocations (as percent)	20.00%	20.00%
Alabama Power [Member] | Other postretirement benefit plans | Domestic Fixed Income Investments [Member]
Liabilities Fair Value
Target plan asset allocations (as percent)	24.00%
Actual plan asset allocations (as percent)	29.00%	27.00%
Alabama Power [Member] | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 7	$ 8
Alabama Power [Member] | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	2
Alabama Power [Member] | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	10	13
Alabama Power [Member] | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	5	6
Alabama Power [Member] | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	14	3
Alabama Power [Member] | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	220	212
Alabama Power [Member] | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	16	19
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 12	$ 14
Liabilities Fair Value
Target plan asset allocations (as percent)	4.00%
Actual plan asset allocations (as percent)	4.00%	5.00%
Alabama Power [Member] | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 2
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 2
Liabilities Fair Value
Target plan asset allocations (as percent)	1.00%
Actual plan asset allocations (as percent)	1.00%	1.00%
Alabama Power [Member] | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 6	$ 7
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 6	$ 7
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	$ 1,079	$ 771
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	477	403
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	292	294
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	236	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	74	74
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	82	77
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	51	57
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	13	14
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	14	1
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	4	5
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	987	1,012
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	220	168
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	264	244
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	140	112
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	3	49
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	235	280
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	124	123
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	1	36
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	264	263
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	10	8
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	12	12
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	7	8
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	2
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	10	13
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	5	6
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	2
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	220	212
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,621	3,196		3,383
Assets Fair Value
Fair Value, Plan Assets	3,615	3,143
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 643	$ 641
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Georgia Power [Member] | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 1,003	$ 801
Liabilities Fair Value
Target plan asset allocations (as percent)	26.00%
Actual plan asset allocations (as percent)	29.00%	30.00%
Georgia Power [Member] | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 800	$ 755
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%
Actual plan asset allocations (as percent)	22.00%	23.00%
Georgia Power [Member] | Pension plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	23.00%
Actual plan asset allocations (as percent)	29.00%	23.00%
Georgia Power [Member] | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 201	$ 157
Georgia Power [Member] | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	4	69
Georgia Power [Member] | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	338	394
Georgia Power [Member] | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	179	173
Georgia Power [Member] | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	341	50
Georgia Power [Member] | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	500	524
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 394	$ 421
Liabilities Fair Value
Target plan asset allocations (as percent)	14.00%
Actual plan asset allocations (as percent)	13.00%	16.00%
Georgia Power [Member] | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 61
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 61
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Georgia Power [Member] | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 188	$ 220
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 188	$ 220
Liabilities Fair Value
Target plan asset allocations (as percent)	9.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Georgia Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 354	$ 358		395
Assets Fair Value
Fair Value, Plan Assets	352	364
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 18	$ 19
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Georgia Power [Member] | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 54	$ 66
Liabilities Fair Value
Target plan asset allocations (as percent)	36.00%
Actual plan asset allocations (as percent)	35.00%	34.00%
Georgia Power [Member] | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 48	$ 53
Liabilities Fair Value
Target plan asset allocations (as percent)	24.00%
Actual plan asset allocations (as percent)	24.00%	27.00%
Georgia Power [Member] | Other postretirement benefit plans | Domestic Fixed Income Investments [Member]
Liabilities Fair Value
Target plan asset allocations (as percent)	33.00%
Actual plan asset allocations (as percent)	35.00%	25.00%
Georgia Power [Member] | Other postretirement benefit plans | Global Fixed Income Investments [Member]
Liabilities Fair Value
Target plan asset allocations (as percent)
Actual plan asset allocations (as percent)		8.00%
Georgia Power [Member] | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 5	$ 5
Georgia Power [Member] | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	2
Georgia Power [Member] | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	9	12
Georgia Power [Member] | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	38	30
Georgia Power [Member] | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	15	16
Georgia Power [Member] | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	162	158
Georgia Power [Member] | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	14	15
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 11	$ 12
Liabilities Fair Value
Target plan asset allocations (as percent)	4.00%
Actual plan asset allocations (as percent)	4.00%	4.00%
Georgia Power [Member] | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 2
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 2
Liabilities Fair Value
Target plan asset allocations (as percent)	1.00%
Actual plan asset allocations (as percent)	1.00%	0.00%
Georgia Power [Member] | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 5	$ 7
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 5	$ 7
Liabilities Fair Value
Target plan asset allocations (as percent)	2.00%
Actual plan asset allocations (as percent)	1.00%	2.00%
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	$ 1,552	$ 1,080
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	686	565
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	420	412
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	340	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	106	103
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	74	55
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	45	30
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	11	12
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	15	10
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	3	3
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	1,420	1,422
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	317	236
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	380	343
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	201	157
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	4	69
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	338	394
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	179	173
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	1	50
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	260	290
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	9	36
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	37	41
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	5	5
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	2
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	9	12
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	38	30
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	6
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	162	158
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Trust-owned life insurance
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	491	420		435
Assets Fair Value
Fair Value, Plan Assets	490	412
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 86	$ 84
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Gulf Power [Member] | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 136	$ 104
Liabilities Fair Value
Target plan asset allocations (as percent)	26.00%
Actual plan asset allocations (as percent)	29.00%	30.00%
Gulf Power [Member] | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 109	$ 99
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%
Actual plan asset allocations (as percent)	22.00%	23.00%
Gulf Power [Member] | Pension plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	23.00%
Actual plan asset allocations (as percent)	29.00%	23.00%
Gulf Power [Member] | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 27	$ 21
Gulf Power [Member] | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	1	9
Gulf Power [Member] | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	47	51
Gulf Power [Member] | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	24	23
Gulf Power [Member] | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	46	7
Gulf Power [Member] | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	67	69
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 53	$ 55
Liabilities Fair Value
Target plan asset allocations (as percent)	14.00%
Actual plan asset allocations (as percent)	13.00%	16.00%
Gulf Power [Member] | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 8
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 8
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Gulf Power [Member] | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 25	$ 29
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 25	$ 29
Liabilities Fair Value
Target plan asset allocations (as percent)	9.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Gulf Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 18	$ 17		18
Assets Fair Value
Fair Value, Plan Assets	19	17
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 3	$ 3
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Gulf Power [Member] | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 5	$ 4
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%
Actual plan asset allocations (as percent)	28.00%	29.00%
Gulf Power [Member] | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 4	$ 4
Liabilities Fair Value
Target plan asset allocations (as percent)	24.00%
Actual plan asset allocations (as percent)	21.00%	22.00%
Gulf Power [Member] | Other postretirement benefit plans | Domestic Fixed Income Investments [Member]
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%
Actual plan asset allocations (as percent)	31.00%	25.00%
Gulf Power [Member] | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 1	$ 1
Gulf Power [Member] | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	2	2
Gulf Power [Member] | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	1	1
Gulf Power [Member] | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	2	1
Gulf Power [Member] | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	3	3
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 2	$ 2
Liabilities Fair Value
Target plan asset allocations (as percent)	14.00%
Actual plan asset allocations (as percent)	13.00%	16.00%
Gulf Power [Member] | Other postretirement benefit plans | Special situations
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Gulf Power [Member] | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 1	$ 1
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 1	$ 1
Liabilities Fair Value
Target plan asset allocations (as percent)	9.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	$ 210	$ 141
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	93	73
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	57	54
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	46	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	14	14
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	8	7
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	3	3
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	2	2
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	2	1
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	1	1
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	194	187
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	43	31
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	52	45
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	27	21
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	1	9
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	47	51
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	24	23
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	7
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	8	7
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	2	1
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	2	2
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	1	1
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	2	2
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	1	1
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	499	430		446
Assets Fair Value
Fair Value, Plan Assets	498	423
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 88	$ 87
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Mississippi Power [Member] | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 139	$ 108
Liabilities Fair Value
Target plan asset allocations (as percent)	26.00%
Actual plan asset allocations (as percent)	29.00%	30.00%
Mississippi Power [Member] | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 109	$ 101
Liabilities Fair Value
Target plan asset allocations (as percent)	25.00%
Actual plan asset allocations (as percent)	22.00%	23.00%
Mississippi Power [Member] | Pension plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	23.00%
Actual plan asset allocations (as percent)	29.00%	23.00%
Mississippi Power [Member] | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 28	$ 21
Mississippi Power [Member] | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	1	9
Mississippi Power [Member] | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	46	53
Mississippi Power [Member] | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	25	23
Mississippi Power [Member] | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	47	7
Mississippi Power [Member] | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	69	71
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 54	$ 57
Liabilities Fair Value
Target plan asset allocations (as percent)	14.00%
Actual plan asset allocations (as percent)	13.00%	16.00%
Mississippi Power [Member] | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	$ 8
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 8
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Mississippi Power [Member] | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 26	$ 30
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 26	$ 30
Liabilities Fair Value
Target plan asset allocations (as percent)	9.00%
Actual plan asset allocations (as percent)	5.00%	6.00%
Mississippi Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 23	$ 23		24
Assets Fair Value
Fair Value, Plan Assets	24	23
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 3	$ 4
Liabilities Fair Value
Target plan asset allocations (as percent)	100.00%
Actual plan asset allocations (as percent)	100.00%	100.00%
Mississippi Power [Member] | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 6	$ 4
Liabilities Fair Value
Target plan asset allocations (as percent)	21.00%
Actual plan asset allocations (as percent)	23.00%	24.00%
Mississippi Power [Member] | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 4	$ 4
Liabilities Fair Value
Target plan asset allocations (as percent)	20.00%
Actual plan asset allocations (as percent)	18.00%	18.00%
Mississippi Power [Member] | Other postretirement benefit plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	38.00%
Actual plan asset allocations (as percent)	43.00%	38.00%
Mississippi Power [Member] | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	$ 5	$ 6
Mississippi Power [Member] | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	2	2
Mississippi Power [Member] | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	1	1
Mississippi Power [Member] | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	2	1
Mississippi Power [Member] | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	3	4
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 2	$ 3
Liabilities Fair Value
Target plan asset allocations (as percent)	11.00%
Actual plan asset allocations (as percent)	10.00%	13.00%
Mississippi Power [Member] | Other postretirement benefit plans | Special situations
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%	2.00%
Mississippi Power [Member] | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	$ 1	$ 1
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 1	$ 1
Liabilities Fair Value
Target plan asset allocations (as percent)	7.00%
Actual plan asset allocations (as percent)	4.00%	5.00%
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	$ 215	$ 145
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	95	76
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	58	55
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	47	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	15	14
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	9	7
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	4	3
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	2	2
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	2	1
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	1	1
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	195	191
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	44	32
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	51	46
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	28	21
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	1	9
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	46	53
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	25	23
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	7
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	12	12
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	2	1
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	2	2
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	5	6
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	2	2
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	1	1
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Special situations
Assets Fair Value
Fair Value, Plan Assets	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Mortgage- and asset-backed securities
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0	0
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0	0
Successor [Member] | Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	983		$ 837
Assets Fair Value
Fair Value, Plan Assets	983
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	100
Successor [Member] | Southern Company Gas [Member] | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	485
Successor [Member] | Southern Company Gas [Member] | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	185
Successor [Member] | Southern Company Gas [Member] | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	85
Successor [Member] | Southern Company Gas [Member] | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	41
Successor [Member] | Southern Company Gas [Member] | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	66
Successor [Member] | Southern Company Gas [Member] | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	100
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	83
Successor [Member] | Southern Company Gas [Member] | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	19
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	15
Successor [Member] | Southern Company Gas [Member] | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	2
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	2
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	105		100
Assets Fair Value
Fair Value, Plan Assets	105
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 2
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Cash and Cash Equivalents [Member]
Liabilities Fair Value
Target plan asset allocations (as percent)	1.00%
Actual plan asset allocations (as percent)	1.00%
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	$ 61
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	$ 18
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Fixed income
Liabilities Fair Value
Target plan asset allocations (as percent)	24.00%
Actual plan asset allocations (as percent)	23.00%
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	$ 23
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	3
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	$ 2
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Equity Securities
Liabilities Fair Value
Target plan asset allocations (as percent)	72.00%
Actual plan asset allocations (as percent)	74.00%
Successor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Other Types Of Investments [Member]
Liabilities Fair Value
Target plan asset allocations (as percent)	3.00%
Actual plan asset allocations (as percent)	2.00%
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	$ 158
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	142
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	12
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	4
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	4
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	3
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	1
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	725
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	343
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	185
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	85
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	41
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	66
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	5
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	99
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	58
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	18
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	23
Successor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Real estate investments
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Domestic equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International equity
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Pooled funds
Assets Fair Value
Fair Value, Plan Assets	0
Successor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash equivalents and other
Assets Fair Value
Fair Value, Plan Assets	$ 0
Predecessor [Member] | Southern Company Gas [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Postretirement Benefits Payable		9
Predecessor [Member] | Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 847	837	906
Liabilities Fair Value
Actual plan asset allocations (as percent)		100.00%
% of Fair Value of Plan Assets		100.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 4
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 242
Liabilities Fair Value
Actual plan asset allocations (as percent)		29.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 151
Liabilities Fair Value
Actual plan asset allocations (as percent)		18.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 91
Liabilities Fair Value
Actual plan asset allocations (as percent)		11.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 20
Liabilities Fair Value
Actual plan asset allocations (as percent)		2.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 274
Liabilities Fair Value
Actual plan asset allocations (as percent)		32.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 81
Liabilities Fair Value
Actual plan asset allocations (as percent)		9.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 125
Liabilities Fair Value
Actual plan asset allocations (as percent)		15.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 28
Liabilities Fair Value
Actual plan asset allocations (as percent)		3.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 508
Liabilities Fair Value
Actual plan asset allocations (as percent)		59.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 40
Liabilities Fair Value
Actual plan asset allocations (as percent)		5.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 42
Liabilities Fair Value
Actual plan asset allocations (as percent)		5.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 102
Liabilities Fair Value
Actual plan asset allocations (as percent)		12.00%
Predecessor [Member] | Southern Company Gas [Member] | Pension Plans, Including 401H Portion of Other Retirement Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 856
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 99	$ 100	$ 99
Liabilities Fair Value
Actual plan asset allocations (as percent)		100.00%
% of Fair Value of Plan Assets		100.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 1
Liabilities Fair Value
Actual plan asset allocations (as percent)		1.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 22
Liabilities Fair Value
Actual plan asset allocations (as percent)		24.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 22
Liabilities Fair Value
Actual plan asset allocations (as percent)		24.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 52
Liabilities Fair Value
Actual plan asset allocations (as percent)		58.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 15
Liabilities Fair Value
Actual plan asset allocations (as percent)		17.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 67
Liabilities Fair Value
Actual plan asset allocations (as percent)		75.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other postretirement benefit plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
Actual plan asset allocations (as percent)		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Other Postretirement Benefits, Excluding 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 90
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 136
Liabilities Fair Value
% of Fair Value of Plan Assets		16.00%
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 4
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		75
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		57
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		132
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pension plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 1
Liabilities Fair Value
% of Fair Value of Plan Assets		1.00%
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 1
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other postretirement benefit plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 618
Liabilities Fair Value
% of Fair Value of Plan Assets		72.00%
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		242
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		151
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		91
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		199
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		24
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		125
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		28
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		376
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Pension plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 89
Liabilities Fair Value
% of Fair Value of Plan Assets		99.00%
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		22
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		22
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		52
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		15
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		67
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Other Observable Inputs (Level 2) | Other postretirement benefit plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 102
Liabilities Fair Value
% of Fair Value of Plan Assets		12.00%
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		20
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		40
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		42
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Pension plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		102
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Liabilities Fair Value
% of Fair Value of Plan Assets		0.00%
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | U.S. Treasury, government, and agency bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Private equity
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | US Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | US Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | International Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Hedge Funds, Global Opportunity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Predecessor [Member] | Southern Company Gas [Member] | Significant Unobservable Inputs (Level 3) | Other postretirement benefit plans | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0

Retirement Benefits - Textual (

Retirement Benefits - Textual (Details) - USD ($)	Dec. 19, 2016	Sep. 12, 2016	Sep. 30, 2016	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 29, 2016
Defined Benefit Plan Disclosure [Line Items]
Annual increase or decrease in assumed medical care cost trend rate						1.00%
Total accumulated benefit obligation for the pension plans				$ 11,300,000,000		$ 11,300,000,000	$ 9,600,000,000
Period over which company has elected to amortize changes in the market value of all plan assets						5 years
Actual plan asset allocations (as percent)							100.00%
Target plan asset allocations (as percent)						100.00%
Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 900,000,000					$ 1,076,000,000	$ 45,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				(3,165,000,000)		(3,165,000,000)	(3,093,000,000)
Expected postretirement trust contributions						0
Projected benefit obligations				12,385,000,000		$ 12,385,000,000	$ 10,542,000,000	$ 10,909,000,000
Annual salary increase on net periodic benefit costs						4.37%	3.59%	3.59%
Actual plan asset allocations (as percent)							100.00%
Target plan asset allocations (as percent)							100.00%
Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 65,000,000	$ 39,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				(360,000,000)		(360,000,000)	(387,000,000)
Expected postretirement trust contributions						0
Projected benefit obligations				$ 2,297,000,000		$ 2,297,000,000	$ 1,989,000,000	$ 1,986,000,000
Annual salary increase on net periodic benefit costs						4.37%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%	100.00%
Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 11,800,000,000		$ 11,800,000,000
Non Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 627,000,000		$ 627,000,000
Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				29.00%		29.00%	23.00%
Target plan asset allocations (as percent)						23.00%	23.00%
Fixed income | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				31.00%		31.00%	30.00%
Target plan asset allocations (as percent)						29.00%	28.00%
Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized						$ 105,000,000	$ 92,000,000	$ 87,000,000
Georgia Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected postretirement trust contributions						$ 0
Annual increase or decrease in assumed medical care cost trend rate						1.00%
Period over which company has elected to amortize changes in the market value of all plan assets						5 years
Georgia Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	287,000,000					$ 301,000,000	14,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				$ (1,112,000,000)		(1,112,000,000)	(1,068,000,000)
Expected postretirement trust contributions						0
Total accumulated benefit obligation for the pension plans				3,500,000,000		3,500,000,000	3,300,000,000
Projected benefit obligations				$ 3,800,000,000		$ 3,800,000,000	$ 3,615,000,000	$ 3,781,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Georgia Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 17,000,000	$ 10,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				$ (207,000,000)		(207,000,000)	(215,000,000)
Projected benefit obligations				$ 847,000,000		$ 847,000,000	$ 854,000,000	$ 864,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Georgia Power [Member] | Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 3,600,000,000		$ 3,600,000,000
Georgia Power [Member] | Non Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 152,000,000		$ 152,000,000
Georgia Power [Member] | Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				29.00%		29.00%	23.00%
Target plan asset allocations (as percent)						23.00%
Georgia Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						85.00%
Georgia Power [Member] | Maximum [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Maximum limit of contribution of employees base salary						6.00%
Georgia Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized						$ 27,000,000	$ 26,000,000	$ 25,000,000
Southern Company Gas [Member]
Defined Benefit Plan Disclosure [Line Items]
Annual increase or decrease in assumed medical care cost trend rate						1.00%
Southern Company Gas [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Regulatory asset					$ 369,000,000
Defined Benefit Plan, Benefit Obligation, Period Increase (Decrease)			$ 177,000,000
Defined Benefit Plan, Fair Value of Plan Assets, Period Increase (Decrease)			(10,000,000)
Southern Company Gas [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Regulatory asset					77,000,000
Defined Benefit Plan, Benefit Obligation, Period Increase (Decrease)			20,000,000
Defined Benefit Plan, Fair Value of Plan Assets, Period Increase (Decrease)			1,000,000
Southern Company Gas [Member] | Employee Savings Plan Option One Contribution Percentage
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						65.00%
Southern Company Gas [Member] | Employee Savings Plan First Matching Contribution Percentage
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						100.00%
Southern Company Gas [Member] | Employee Saving Plan
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						75.00%
Southern Company Gas [Member] | Successor [Member]
Defined Benefit Plan Disclosure [Line Items]
Total accumulated benefit obligation for the pension plans				$ 1,100,000,000		$ 1,100,000,000
Southern Company Gas [Member] | Successor [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions		$ 125,000,000		129,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				(226,000,000)		(226,000,000)
Expected postretirement trust contributions						0
Projected benefit obligations				$ 1,133,000,000	1,244,000,000	1,133,000,000
Annual salary increase on net periodic benefit costs				3.50%
Southern Company Gas [Member] | Successor [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				$ 11,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				(61,000,000)		(61,000,000)
Expected postretirement trust contributions						0
Projected benefit obligations				$ 308,000,000	338,000,000	308,000,000
Annual salary increase on net periodic benefit costs				3.50%
Southern Company Gas [Member] | Successor [Member] | Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 1,100,000,000		1,100,000,000
Southern Company Gas [Member] | Successor [Member] | Non Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 39,000,000		$ 39,000,000
Southern Company Gas [Member] | Successor [Member] | Fixed income | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				23.00%		23.00%
Target plan asset allocations (as percent)						24.00%
Southern Company Gas [Member] | Successor [Member] | Other Types Of Investments [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				2.00%		2.00%
Target plan asset allocations (as percent)						3.00%
Southern Company Gas [Member] | Successor [Member] | Equity Securities | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				74.00%		74.00%
Target plan asset allocations (as percent)						72.00%
Southern Company Gas [Member] | Successor [Member] | Cash and Cash Equivalents [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				1.00%		1.00%
Target plan asset allocations (as percent)						1.00%
Southern Company Gas [Member] | Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Total accumulated benefit obligation for the pension plans							1,000,000,000
Southern Company Gas [Member] | Predecessor [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions					1,000,000		2,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax							(374,000,000)
Projected benefit obligations					$ 1,244,000,000		$ 1,067,000,000	$ 1,098,000,000
Annual salary increase on net periodic benefit costs					3.70%		3.70%	3.70%
Actual plan asset allocations (as percent)							100.00%
Southern Company Gas [Member] | Predecessor [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions					$ 10,000,000		$ 17,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax							(81,000,000)
Projected benefit obligations					$ 338,000,000		$ 318,000,000	$ 334,000,000
Annual salary increase on net periodic benefit costs					3.70%		3.70%	3.70%
Actual plan asset allocations (as percent)							100.00%
Southern Company Gas [Member] | Predecessor [Member] | Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							29.00%
Southern Company Gas [Member] | Predecessor [Member] | Fixed income | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							24.00%
Southern Company Gas [Member] | Predecessor [Member] | Other Types Of Investments [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							12.00%
Southern Company Gas [Member] | Predecessor [Member] | Other Types Of Investments [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							0.00%
Southern Company Gas [Member] | Predecessor [Member] | Equity Securities | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							59.00%
Southern Company Gas [Member] | Predecessor [Member] | Equity Securities | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							75.00%
Southern Company Gas [Member] | Predecessor [Member] | Cash and Cash Equivalents [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							0.00%
Southern Company Gas [Member] | Predecessor [Member] | Cash and Cash Equivalents [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							1.00%
Southern Company Gas [Member] | Pension and Other Postretirement Plans Costs [Member] | Successor [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory asset			$ 437,000,000
Southern Company Gas [Member] | Maximum [Member] | Employee Savings Plan Option One Contribution Percentage
Defined Benefit Plan Disclosure [Line Items]
Maximum limit of contribution of employees base salary						8.00%
Southern Company Gas [Member] | Maximum [Member] | Employee Savings Plan First Matching Contribution Percentage
Defined Benefit Plan Disclosure [Line Items]
Maximum limit of contribution of employees base salary						3.00%
Southern Company Gas [Member] | Maximum [Member] | Employee Saving Plan
Defined Benefit Plan Disclosure [Line Items]
Maximum limit of contribution of employees base salary						3.00%
Southern Company Gas [Member] | Employee Savings Plan | Successor [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized						$ 8,000,000
Southern Company Gas [Member] | Employee Savings Plan | Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized					$ 10,000,000		$ 16,000,000	$ 14,000,000
Southern Company Gas [Member] | AGL Resources Inc. Retirement Plan | Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized					$ 2,000,000		2,000,000	1,000,000
Alabama Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected postretirement trust contributions						$ 0
Annual increase or decrease in assumed medical care cost trend rate						1.00%
Total accumulated benefit obligation for the pension plans				$ 2,400,000,000		$ 2,400,000,000	2,300,000,000
Period over which company has elected to amortize changes in the market value of all plan assets						5 years
Alabama Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	129,000,000					$ 141,000,000	12,000,000
Expected postretirement trust contributions						0
Projected benefit obligations				$ 2,663,000,000		$ 2,663,000,000	$ 2,506,000,000	$ 2,592,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Alabama Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 7,000,000	$ 1,000,000
Projected benefit obligations				$ 501,000,000		$ 501,000,000	$ 505,000,000	$ 503,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Alabama Power [Member] | Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 2,500,000,000		$ 2,500,000,000
Alabama Power [Member] | Non Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 124,000,000		$ 124,000,000
Alabama Power [Member] | Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				29.00%		29.00%	23.00%
Target plan asset allocations (as percent)						23.00%
Alabama Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						85.00%
Maximum limit of contribution of employees base salary						6.00%
Alabama Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized						$ 23,000,000	$ 22,000,000	$ 21,000,000
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
Regulatory asset									$ 63,000,000
Gulf Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	48,000,000					$ 49,000,000	1,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				$ (150,000,000)		(150,000,000)	(140,000,000)
Total accumulated benefit obligation for the pension plans				460,000,000		460,000,000	424,000,000
Projected benefit obligations				$ 517,000,000		$ 517,000,000	$ 480,000,000	$ 491,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Gulf Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 3,000,000	$ 3,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				$ 7,000,000		7,000,000	5,000,000
Expected postretirement trust contributions						0
Projected benefit obligations				$ 83,000,000		$ 83,000,000	$ 81,000,000	$ 78,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Gulf Power [Member] | Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Expected postretirement trust contributions						$ 0
Projected benefit obligations				$ 494,000,000		494,000,000
Gulf Power [Member] | Non Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 23,000,000		$ 23,000,000
Gulf Power [Member] | Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				29.00%		29.00%	23.00%
Target plan asset allocations (as percent)						23.00%
Gulf Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						85.00%
Maximum limit of contribution of employees base salary						6.00%
Gulf Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized						$ 5,000,000	$ 4,000,000	$ 4,000,000
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				$ 479,000,000		$ 479,000,000	447,000,000
Period over which company has elected to amortize changes in the market value of all plan assets						5 years
Mississippi Power [Member] | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 47,000,000					$ 50,000,000	2,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				(151,000,000)		(151,000,000)	(142,000,000)
Projected benefit obligations				$ 534,000,000		$ 534,000,000	$ 500,000,000	$ 513,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Mississippi Power [Member] | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions						$ 4,000,000	$ 3,000,000
Expected postretirement trust contributions						0
Projected benefit obligations				$ 97,000,000		$ 97,000,000	$ 97,000,000	$ 96,000,000
Annual salary increase on net periodic benefit costs						4.46%	3.59%	3.59%
Actual plan asset allocations (as percent)				100.00%		100.00%	100.00%
Target plan asset allocations (as percent)						100.00%
Mississippi Power [Member] | Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Expected postretirement trust contributions						$ 0
Projected benefit obligations				$ 504,000,000		504,000,000
Mississippi Power [Member] | Non Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations				$ 30,000,000		$ 30,000,000
Mississippi Power [Member] | Fixed income | Pension plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				29.00%		29.00%	23.00%
Target plan asset allocations (as percent)						23.00%
Mississippi Power [Member] | Fixed income | Other postretirement benefit plans
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				43.00%		43.00%	38.00%
Target plan asset allocations (as percent)						38.00%
Mississippi Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Matching limit of contribution by employer						85.00%
Maximum limit of contribution of employees base salary						6.00%
Mississippi Power [Member] | Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized						$ 5,000,000	$ 5,000,000	$ 5,000,000
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Successor [Member] | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				20.00%		20.00%
Target plan asset allocations (as percent)						15.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Successor [Member] | Other Types Of Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				10.00%		10.00%
Target plan asset allocations (as percent)						30.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Successor [Member] | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				69.00%		69.00%
Target plan asset allocations (as percent)						53.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Successor [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)				1.00%		1.00%
Target plan asset allocations (as percent)						2.00%	10.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Predecessor [Member] | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							28.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Predecessor [Member] | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocations (as percent)							72.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Minimum [Member] | Successor [Member] | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)							5.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Minimum [Member] | Successor [Member] | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)							70.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Maximum [Member] | Successor [Member] | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)							20.00%
AGL Resources Inc. Retirement Plan | Southern Company Gas [Member] | Maximum [Member] | Successor [Member] | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations (as percent)							95.00%

Contingencies and Regulatory 73

Contingencies and Regulatory Matters - Textual - General, Environmental Remediation, Nuclear Fuel Costs, FERC Matters (Details) $ in Millions

Feb. 02, 2017

Jan. 01, 2017USD ($)

Dec. 13, 2016

Aug. 17, 2016USD ($)

Jun. 09, 2016USD ($)

May 01, 2016USD ($)

Mar. 31, 2016

Apr. 01, 2015USD ($)

May 01, 2014USD ($)

Sep. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Jul. 31, 2015USD ($)

Mar. 31, 2015USD ($)

Mar. 15, 2017USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)stateutilitypipelinedefendantsite

Dec. 31, 2014USD ($)installment

Dec. 31, 2013

Dec. 20, 2016USD ($)

Dec. 31, 2015USD ($)

Mississippi Power [Member]

Loss Contingencies [Line Items]

Regulatory Asset, Deferral Period

10 years

Finite-lived Asset, Remaining Life

30 years

AFUDC Cost

$ 14

Increase in Base Rate Under Cost Based Electric Tariff Due to Settlement

$ 7

$ 10

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 18

Over Recovered Fuel Cost

$ 71

Georgia Power [Member]

Loss Contingencies [Line Items]

Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation

$ 17

Claims Awarded to Companies Related to Nuclear Fuel Disposal Litigation

$ 18

Loss Contingency, Estimate of Possible Loss

$ 240

Gulf Power [Member]

Loss Contingencies [Line Items]

Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation

$ 44

Southern Company Gas [Member]

Loss Contingencies [Line Items]

Number of states in which entity operates | state

7

Number of natural gas distribution utilities | utility

7

Nicor Gas [Member]

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 0.3

Alabama Power [Member]

Loss Contingencies [Line Items]

Claims Awarded to Companies Related to Nuclear Fuel Disposal Litigation

$ 26

Over Recovered Fuel Cost

$ 76

238

Virginia Natural Gas

Loss Contingencies [Line Items]

Period to File Subsequent Rate Request

60 days

Scenario, Forecast [Member] | Mississippi Power [Member]

Loss Contingencies [Line Items]

AFUDC Cost

$ 14

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 22

Successor [Member] | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Environmental Exit Costs, Costs Accrued to Date

426

Environmental Exit Costs, Costs Accrued to Date, Incur Next Twelve Months

69

Predecessor [Member] | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Increase (Decrease) in Insurance Settlements Receivable

$ 77

Insurance Settlements Receivable Number Of Installments | installment

2

Proceeds from Insurance Settlement, Operating Activities

$ 32

$ 45

Location One [Member] | Successor [Member] | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation

5

Gas pipeline | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Approved Infrastructure Replacement Program

780

Under Recovered Regulatory Clause Revenues and Other Current Liabilities [Member] | Gulf Power [Member]

Loss Contingencies [Line Items]

Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation

4

Other Regulatory Assets, Deferred and Other Deferred Credits and Liabilities [Member] | Gulf Power [Member]

Loss Contingencies [Line Items]

Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation

40

Kemper IGCC [Member] | Mississippi Power [Member]

Loss Contingencies [Line Items]

AFUDC Cost

$ 11

Period of Amortization of Regulatory Assets

36 months

MRA Revenue [Member] | Mississippi Power [Member]

Loss Contingencies [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (11)

Over Recovered Fuel Cost

$ 13

$ 24

MB Revenue [Member] | Mississippi Power [Member]

Loss Contingencies [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (1)

Subsequent Event [Member] | Gulf Power [Member]

Loss Contingencies [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (41)

Subsequent Event [Member] | Traditional Operating Companies and Southern Power [Member]

Loss Contingencies [Line Items]

Period to File Subsequent Rate Request

30 days

Subsequent Event [Member] | MRA Revenue [Member] | Mississippi Power [Member]

Loss Contingencies [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 10

Pending Litigation [Member] | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Number of states in which entity operates | state

1

Number of natural gas distribution utilities | utility

1

Loss Contingency, Number of Defendants | defendant

1

Pending Litigation [Member] | Kemper IGCC [Member] | Mississippi Power [Member]

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 100

Minimum [Member] | Pending Litigation [Member] | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Loss Contingency, Estimate of Possible Loss

$ 11

Manufactured Gas Plants [Member] | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Number of states in which entity operates | state

5

# of sites | site

46

Midstream Operations [Member] | Gas pipeline | Southern Company Gas [Member]

Loss Contingencies [Line Items]

Number of Gas Construction Projects | pipeline

3

Contingencies and Regulatory 74

Contingencies and Regulatory Matters - Textual - Regulatory Matters (Details)	Feb. 21, 2017USD ($)	Feb. 14, 2017USD ($)	Jan. 01, 2017USD ($)	Dec. 31, 2016USD ($)utility	Dec. 20, 2016USD ($)	Dec. 13, 2016	Dec. 06, 2016USD ($)$ / KWH_Kilowatt_hour	Dec. 05, 2016USD ($)	Oct. 12, 2016USD ($)	Sep. 01, 2016USD ($)	Aug. 17, 2016USD ($)	Aug. 01, 2016USD ($)	Jul. 28, 2016MW	Mar. 09, 2016USD ($)mi	Jan. 01, 2016USD ($)	Jan. 01, 2015USD ($)	Jan. 01, 2013	Dec. 31, 2016USD ($)utility$ / KWH_Kilowatt_hour	Jul. 31, 2016USD ($)	Nov. 30, 2015$ / KWH_Kilowatt_hour	Oct. 31, 2015USD ($)	Sep. 30, 2015USD ($)stationmi	Apr. 30, 2015MW	Dec. 31, 2016USD ($)utility	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)utility	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)$ / KWH_Kilowatt_hour	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)utilityrate_plan_filing$ / KWH_Kilowatt_hour	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)MW	Dec. 31, 2013USD ($)Customermi	Dec. 31, 2012USD ($)	Dec. 31, 2009USD ($)	Dec. 31, 2008USD ($)MW	Sep. 30, 2015USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2022	Jun. 30, 2016USD ($)	Jan. 01, 2121	Jan. 01, 2021	Jun. 30, 2019USD ($)	Oct. 01, 2017$ / item	Feb. 17, 2017USD ($)	Feb. 03, 2017USD ($)	Dec. 01, 2016USD ($)	Nov. 30, 2016USD ($)	Oct. 01, 2016$ / item	Aug. 31, 2016	Aug. 29, 2016USD ($)	Jun. 17, 2016USD ($)	May 17, 2016USD ($)	May 03, 2016USD ($)	Mar. 31, 2016MW	Jan. 05, 2016USD ($)	Oct. 01, 2015$ / item	Feb. 28, 2015USD ($)	Sep. 30, 2014
Schedule of Regulatory Assets and Liabilities [Line Items]
Other Regulatory Assets Current				$ 581,000,000														$ 581,000,000						$ 581,000,000		$ 581,000,000				$ 581,000,000	$ 580,000,000
Line of Credit Facility, Maximum Borrowing Capacity				8,443,000,000														8,443,000,000						8,443,000,000		8,443,000,000				8,443,000,000
Construction in Progress, Gross				8,977,000,000														8,977,000,000						8,977,000,000		8,977,000,000				8,977,000,000	9,082,000,000
Other Cost of Removal Obligations				2,748,000,000														2,748,000,000						2,748,000,000		2,748,000,000				$ 2,748,000,000	1,162,000,000
Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Performance Evaluation Plan, Number Of Filings Per Calendar Year | rate_plan_filing																														2
Other Regulatory Assets Current				115,000,000														115,000,000						115,000,000		115,000,000				$ 115,000,000	95,000,000
Over Recovered Fuel Cost																															71,000,000
Approved Increase (Decrease) in Annual Billing Based on Fuel Cost Recovery Rate											$ (51,000,000)																																													$ (120,000,000)
Storm Restoration Costs				0														0						0		0				0
Line of Credit Facility, Maximum Borrowing Capacity				173,000,000														173,000,000						173,000,000		173,000,000				173,000,000
Construction in Progress, Gross				2,545,000,000														2,545,000,000						2,545,000,000		2,545,000,000				2,545,000,000	2,254,000,000
Other Cost of Removal Obligations				$ 170,000,000														$ 170,000,000						$ 170,000,000		$ 170,000,000				$ 170,000,000	165,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount											$ 18,000,000
Annual PEP Lookback Refund To Customers																																	$ 5,000,000
Annual PEP Filing Rate Increase																																	1.90%
Annual PEP Filing Rate Increase Amount																																	$ 15,000,000
Anticipates of Elimination Adjustment will Result in Additional Revenues																																	$ 3,000,000
Gain Contingency, Surcharge Revenue																															5,000,000
Required Customers For Energy Efficiency Programs | Customer																																	25,000
Required Period For Filing Quick Start Plans																																	6 months
PSC Retail Rate Increase (Decrease)																																																$ 1,000,000				$ (1,000,000)		$ (2,000,000)
Regulatory amortization period																			5 years
Percentage Of PSC Retail Rate Increase (Decrease)																																																				(0.07%)
System Restoration Rider Rate																					0.00%
Psc approved annual property damage reserve accrual																					$ 3,000,000
Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Adjusting Point Of Weighted Cost Of Equity				5.98%														5.98%						5.98%		5.98%				5.98%
Percent Of Basis Points Increase (Decrease)				(0.07%)														(0.07%)						(0.07%)		(0.07%)				(0.07%)																	(0.07%)
Other Regulatory Assets Current				$ 149,000,000														$ 149,000,000						$ 149,000,000		$ 149,000,000				$ 149,000,000	182,000,000
Rate Adjustment Period																														2 years
Maximum Percentage of Rate RSE																														4.00%
Maximum Annual Percentage of Ratio Rate																														5.00%
Rate RSE Increase																																															4.48%
Rate RSE Increase Amount																																															$ 245,000,000
Rate RSE Refund Liability				73,000,000														73,000,000						73,000,000		73,000,000				$ 73,000,000
Under Recovered Certified Power Purchase Agreements				142,000,000														142,000,000						142,000,000		142,000,000				142,000,000	99,000,000
Over (Under) Recovered Environmental Clause				9,000,000														$ 9,000,000						9,000,000		9,000,000				$ 9,000,000
Current Billing Rates Under Rate ECR in Terms of Per Units | $ / KWH_Kilowatt_hour							0.02015																							0.05910
Future Stated Rates Under Rate Ecr Factor In Terms Of Per Units | $ / KWH_Kilowatt_hour																		0.02030		0.02681
Over Recovered Fuel Cost				76,000,000														$ 76,000,000						76,000,000		76,000,000				$ 76,000,000	238,000,000
Rate ECR Increase Decrease							(0.15%)
Rate ECR Increase Decrease Amount							$ (8,000,000)
Maximum Period for Recovery Deferred Storm Related Operations and Maintenance Costs and Any Future Reserve Deficits																														24 months
Maximum Rate NDR Charge Per Month, Monthly Nonresidential Customer Account				10														10						10		10				$ 10
Maximum Rate NDR Charge Per Month, Monthly Residential Customer Account				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
Jointly Owned Utility Plant, Proportionate Ownership Share				14.00%														14.00%						14.00%		14.00%				14.00%
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,335,000,000														$ 1,335,000,000						$ 1,335,000,000		$ 1,335,000,000				$ 1,335,000,000
Construction in Progress, Gross				491,000,000														491,000,000						491,000,000		491,000,000				491,000,000	801,000,000
Percent Of Designated Customer Value Benchmark Survey																																																											33.30%
Other Cost of Removal Obligations				$ 684,000,000														$ 684,000,000						$ 684,000,000		$ 684,000,000				$ 684,000,000	722,000,000
Amortization of regulatory assets																																$ 123,000,000
Regulatory liability amortization																																120,000,000
Non-nuclear Outage Costs																																95,000,000
Compliance And Pension Costs																																28,000,000
Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Percent Of Basis Points Increase (Decrease)				(0.25%)														(0.25%)						(0.25%)		(0.25%)				(0.25%)
Other Regulatory Assets Current				$ 44,000,000														$ 44,000,000						$ 44,000,000		$ 44,000,000				$ 44,000,000	$ 90,000,000
Retail Rate Of Return On Common Equity																															10.25%
Public Utilities, Approved Return on Equity, Percentage									11.00%																					10.25%
Regulatory asset																																																			$ 63,000,000
Line of Credit Facility, Maximum Borrowing Capacity				280,000,000														280,000,000						280,000,000		280,000,000				$ 280,000,000
Construction in Progress, Gross				51,000,000														51,000,000						51,000,000		51,000,000				51,000,000	$ 48,000,000
Base Revenue In Year One																																	$ 35,000,000
Base Revenue In Year Two																																	$ 20,000,000
Other Cost of Removal Obligations				249,000,000														249,000,000						249,000,000		249,000,000				249,000,000	233,000,000
Reduction In Depreciation Expense																														$ 0	20,100,000	8,400,000
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 106,800,000
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%
Cost of Project One				316,000,000														316,000,000						316,000,000		316,000,000				$ 316,000,000
Period of Establishment of Conservation Goals, in Years																														5 years
Period Numeric Conservation Goals Cover, in Years																														10 years
Psc approved annual property damage reserve accrual				$ 3,500,000														$ 3,500,000						$ 3,500,000		$ 3,500,000				$ 3,500,000
Gulf Power and Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share				50.00%														50.00%						50.00%		50.00%				50.00%
Cost of Project One				$ 653,000,000														$ 653,000,000						$ 653,000,000		$ 653,000,000				$ 653,000,000
Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Portion of Actual Earnings Above Approved ROE Band Refunded to Customers																	66.67%													66.67%
Other Regulatory Assets Current				193,000,000														193,000,000						193,000,000		193,000,000				$ 193,000,000	$ 213,000,000
Increase (Decrease) in Base Tariff Rate															$ 49,000,000	$ 107,000,000
Increase (Decrease) In ECCR Tariff															75,000,000	23,000,000
Increase (Decrease) In Demand Side Management Tariff															3,000,000	3,000,000
Increase (Decrease) In Municipal Franchise Fee Tariff															13,000,000	3,000,000
Increase (Decrease) in Revenue to be Received from Base Rate Change															$ 140,000,000	136,000,000
Retail Rate Of Return On Common Equity																	10.95%																10.95%
Public Utilities, Approved Return on Equity, Percentage															10.00%
Revenue Subject To Refund																														11,000,000
Capacity Of Units Included in Application Request By Subsidiaries For Future Period Requests | MW													1,200
Capacity of Renewable Resources Approved For Self-build | MW													200
Approved Increase (Decrease) in Annual Billing Based on Fuel Cost Recovery Rate															$ (350,000,000)																																						$ (313,000,000)
Adjustment To Fuel Cost Recovery Rate If Under Recovered Fuel Balance Exceeds Budget Thereafter																														$ 200,000,000
Required Period For Options And Hedges																														48 months	24 months
Over Recovered Fuel Balance				84,000,000														84,000,000						84,000,000		84,000,000				$ 84,000,000	$ 116,000,000
Storm Restoration Costs				121,000,000														121,000,000						121,000,000		121,000,000				121,000,000
Accrual Under Alternate Rate Plan																														30,000,000
Electric Generating Capacity in Mega Watts Under Consortium Agreement | MW																																				1,100
Liquidated Damages, Percentage																																				10.00%
Additional Construction Capital Costs					$ 3,300,000,000																					222,000,000														$ 3,700,000,000
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
Estimated In-service Capital Cost																																			$ 4,418,000,000
NCCR Tariff															$ 19,000,000	$ 27,000,000																368,000,000
Increase (Decrease) In Projected Certified Construction Capital Costs																														5.00%
Loss Contingency, Estimate of Possible Loss					$ 240,000,000
Construction in Progress, Gross				4,939,000,000														4,939,000,000						4,939,000,000		4,939,000,000				$ 4,939,000,000	4,775,000,000
Portion of Actual Earnings Above Approved ROE Band Retained by Subsidiary Company																	33.33%													33.33%
Regulatory liability amortization																														$ 14,000,000	$ 14,000,000	$ 14,000,000
Southern Company Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 2,000,000,000														$ 2,000,000,000						$ 2,000,000,000		$ 2,000,000,000				$ 2,000,000,000
Number of natural gas distribution utilities | utility				7														7						7		7				7
Nicor Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 700,000,000														$ 700,000,000						$ 700,000,000		$ 700,000,000				$ 700,000,000
Loss Contingency, Damages Sought, Value																						$ 300,000
Elizabethtown Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Business Combination, Regulatory Approval Requirements, Required Rate Credit Payments to Customers																								$ 400,000	$ 17,500,000
Virginia Natural Gas
Schedule of Regulatory Assets and Liabilities [Line Items]
Period to File Subsequent Rate Request						60 days
Minimum [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Potential Period For Next Depreciation Study																														3 years
Minimum [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Period For Quick Start Plans To Be In Effect																																	2 years
Minimum [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Weighted Cost Of Equity				5.75%														5.75%						5.75%		5.75%				5.75%
Minimum [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Percent Of Basis Points Increase (Decrease)				(0.75%)														(0.75%)						(0.75%)		(0.75%)				(0.75%)
Retail Rate Of Return On Common Equity																															9.25%
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue																														10.00%
Minimum [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Retail Rate Of Return On Common Equity																	10.00%
Liquidated Damages, Monetary Amount																																				$ 920,000,000
Maximum [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Potential Period For Next Depreciation Study																														5 years
Maximum [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Period For Quick Start Plans To Be In Effect																																	3 years
Public Utilities, Approved Rate Increase (Decrease), Percentage											2.00%
Maximum [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Weighted Cost Of Equity				6.21%														6.21%						6.21%		6.21%				6.21%
Rate RSE Increase																																															3.52%
Maximum [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Retail Rate Of Return On Common Equity																															11.25%
Maximum [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Retail Rate Of Return On Common Equity																	12.00%
Capacity of Renewable Resources Considered For Renewable Commercial and Industrial Program | MW													200
Liquidated Damages, Monetary Amount																																				930,000,000
Additional Construction Capital Costs																																				$ 114,000,000
Maximum [Member] | Nicor Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Infrastructure Investment, Annual Customer Rate Increase																																	4.00%
Regulatory Clause Revenues, under-recovered [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Over (Under) Recovered Fuel Balance				$ 15,000,000														$ 15,000,000						$ 15,000,000		$ 15,000,000				$ 15,000,000
Over (Under) Recovered Environmental Cost				8,000,000														8,000,000						8,000,000		8,000,000				8,000,000	$ 0
Under Recovered Energy Conservation Costs				4,000,000														4,000,000						4,000,000		4,000,000				4,000,000
Other regulatory liabilities current [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Over (Under) Recovered Fuel Balance																															18,000,000
Over Recovered Energy Conservation Costs																															4,000,000
Regulatory Assets [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Under Recovered Certified Power Purchase Agreements				69,000,000														69,000,000						69,000,000		69,000,000				69,000,000
Over Recovered Regulatory Clause Revenues, Current [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Over Recovered Fuel Balance																															10,000,000
Other deferred credits and liabilities [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Over Recovered Fuel Balance																															106,000,000
Storm damage reserves | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Storm Restoration Costs				116,000,000														116,000,000						116,000,000		116,000,000				116,000,000
Scenario, Forecast [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																													$ 22,000,000
Scenario, Forecast [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Future Stated Rates Under Rate Ecr Factor In Terms Of Per Units | $ / KWH_Kilowatt_hour																												0.05910
Scenario, Forecast [Member] | Georgia Power And Atlanta Gas Light Company [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Percentage Basis, Net Merger Savings																																							40.00%
Scenario, Forecast [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Percent Of Basis Points Increase (Decrease)																																						0.95%			3.00%	3.00%
Customer Refund																													40,000,000
Additional Construction Capital Costs																																						$ 5,440,000,000
Increase (Decrease) in Basis Points																																						(8,000,000)
Amendment To Estimated In-service Capital Cost																																						$ 5,680,000,000
Scenario, Forecast [Member] | Maximum [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Cost Recovery, New Nuclear																																											$ 99,000,000
Plant Sweatt Units 1 And 2 [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Unit Conversion To Non-fossil Fuel Source | MW																																80
Plant Watson Units 4 And 5 [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Unit Conversion To Non-fossil Fuel Source | MW																																750
Plant Scherer Unit 3 [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																														12,000,000
Plant Scherer Unit 3 [Member] | Scenario, Forecast [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																													14,000,000
Public Utilities, Approved Rate Incremental Increase (Decrease), Amount																													$ 2,000,000
Plant Gorgas Units 6 and 7 [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW																							200
Plant Barry Units 1 And 2 [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW																							250
Plant Barry Unit 3 [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW																							225
Plant Greene County Units 1 And 2 [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Unit Conversion To Non-fossil Fuel Source | MW																																200
Regulatory asset				17,000,000														17,000,000						17,000,000		17,000,000				17,000,000
Plant Greene County Units 1 And 2 [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW																							300
Plant Mitchell Units 3, 4A, and 4B [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW													217
Plant Kraft Unit 1 [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW													17
Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Construction in Progress, Gross				3,900,000,000														$ 3,900,000,000						$ 3,900,000,000		$ 3,900,000,000				3,900,000,000
Construction Financing Costs				$ 1,300,000,000
Production Tax Credit , Amount Per Unit, Net Present Value																														$ 400,000,000
Plant Vogtle Units 3 And 4 [Member] | Scenario, Forecast [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Monthly Financing Costs																											$ 30,000,000
Construction Financing Costs																											2,500,000,000
Monthly Operational Readiness Costs																											$ 6,000,000
Plant Smith Units 1 and 2 [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Approved For Decertification | MW																																																							357
Plant Watson [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory asset																			$ 41,000,000
Customers [Member] | Scenario, Forecast [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Percentage Basis, Net Merger Savings																																							60.00%
Subsequent Event [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Revenue Requirement Increase (Decrease), Amount		$ 18,000,000
System Restoration Rider Rate																																														0.00%
Psc approved annual property damage reserve accrual																																														$ 4,000,000
Subsequent Event [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ (41,000,000)
Subsequent Event [Member] | Maximum [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		2.00%
Subsequent Event [Member] | Regulatory Assets [Member] | Alabama Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Over (Under) Recovered Environmental Clause																																													$ (36,000,000)
Subsequent Event [Member] | Scenario, Forecast [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Revenue Requirement Increase (Decrease), Amount																												$ 27,000,000
Plant Daniel Units 1 and 2 [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share				50.00%														50.00%						50.00%		50.00%				50.00%
Plant Daniel Units 1 and 2 [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share				50.00%														50.00%						50.00%		50.00%				50.00%
Intercession City Combustion Turbine [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Capacity Of Units Included In Request To Sell | MW													143
Jointly Owned Utility Plant, Proportionate Ownership Share																																																		33.00%
Storm Costs [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory asset				$ 206,000,000														$ 206,000,000						$ 206,000,000		$ 206,000,000				$ 206,000,000
Property Damage Reserves Liability [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Other Regulatory Assets Current				30,000,000														30,000,000						30,000,000		30,000,000				30,000,000	30,000,000
Regulatory asset				206,000,000														206,000,000						206,000,000		206,000,000				206,000,000	92,000,000
Illinois Commission Staff [Member] | Nicor Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Loss Contingency, Damages Sought, Value																																$ 18,000,000
Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity																															920,000,000
Settlement Agreement [Member] | Gulf Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Other Cost of Removal Obligations				$ 62,500,000														$ 62,500,000						$ 62,500,000		$ 62,500,000				$ 62,500,000
Citizens Utility Board (CUB) [Member] | Nicor Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Loss Contingency, Damages Sought, Value																																$ 22,000,000
Pending Litigation [Member] | Southern Company Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Number of natural gas distribution utilities | utility				1														1						1		1				1
Pending Litigation [Member] | Minimum [Member] | Southern Company Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Loss Contingency, Estimate of Possible Loss				$ 11,000,000														$ 11,000,000						$ 11,000,000		$ 11,000,000				$ 11,000,000
Pending Litigation [Member] | Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Project Settlement Cost To Be Capitalized				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				$ 263,000,000														$ 263,000,000						$ 263,000,000		$ 263,000,000				$ 263,000,000
Capital Projects Associated with Infrastructure Improvement Programs [Member] | Southern Company Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Number of natural gas distribution utilities | utility				6														6						6		6				6
Regulatory Infrastructure Program [Member] | Nicor Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																																9 years
Infrastructure Program [Member] | Minimum [Member] | Southern Company Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																														4 years
Infrastructure Program [Member] | Maximum [Member] | Southern Company Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																														10 years
STRIDE [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																																	4 years
STRIDE [Member] | i-SRP [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period												4 years
Infrastructure Replacement Program, Petitioned Investment Amount (more than)												$ 177,000,000
Approved Infrastructure Replacement Program																																	$ 445,000,000
Infrastructure Replacement Program, Cost Recovery Period																																	10 years
Infrastructure Programs, Plan Filing Frequency																																	3 years
STRIDE [Member] | i-SRP [Member] | Subsequent Event [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period	4 years
Infrastructure Replacement Program, Petitioned Investment Amount (more than)	$ 177,000,000
STRIDE [Member] | i-CGP [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Approved Infrastructure Replacement Program																																	$ 91,000,000
STRIDE [Member] | i-VPR [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Approved Infrastructure Replacement Program																																	$ 275,000,000
Regulated Operations, Natural Gas Pipeline Length, Approved for Replacement | mi																																	756
Regulated Operations, Natural Gas Pipeline Length, Considered for Replacement | mi																																	3,300
STRIDE [Member] | i-VPR [Member] | Minimum [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulated Operations, Period For Replacement																																	15 years
STRIDE [Member] | i-VPR [Member] | Maximum [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulated Operations, Period For Replacement																																	20 years
AIR [Member] | Elizabethtown Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																																	4 years				1 year
Fair Value Inputs, Discount Rate																																	6.65%
Public Utilities, Requested Revenue Requirement Increase (Decrease), Amount								$ 20,000,000		$ 19,000,000
Approved Infrastructure Replacement Program																																$ 15,000,000	$ 115,000,000
Public Utilities, Requested Return on Equity, Percentage										10.25%
Safety, Modernization and Reliability Tariff (SMART) Plan [Member] | Elizabethtown Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Infrastructure Replacement Program, Petitioned Investment Amount (more than)																						$ 1,100,000,000															$ 1,100,000,000
Regulated Operations, Natural Gas Pipeline Length, Considered for Replacement | mi																						630
Regulated Operations, Number of Regulator Stations, Considered for Replacement | station																						240
Regulated Operations, Rider Surcharge, Recovery Period																						10 years
Safety, Modernization and Reliability Tariff (SMART) Plan [Member] | Subsequent Event [Member] | Elizabethtown Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Infrastructure Replacement Program, Petitioned Investment Amount (more than)	$ 1,100,000,000
SAVE [Member] | Virginia Natural Gas
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																																		5 years
Regulated Operations, Natural Gas Pipeline Length, Approved for Replacement | mi														200
Approved Infrastructure Replacement Program, Allowed Amount To Exceed				$ 2,000,000														$ 2,000,000						$ 2,000,000		$ 2,000,000				$ 2,000,000
SAVE [Member] | Maximum [Member] | Virginia Natural Gas
Schedule of Regulatory Assets and Liabilities [Line Items]
Approved Infrastructure Replacement Program, Amount Per Year																																		$ 25,000,000
Approved Infrastructure Replacement Program																																		$ 105,000,000
Approved Infrastructure Replacement Program, Allowed Amount To Exceed														$ 5,000,000
Approved Infrastructure Replacement Program, Approved Investment Amount, Current Fiscal Year														30,000,000
Approved Infrastructure Replacement Program, Approved Investment Amount, Year Two														35,000,000
Approved Infrastructure Replacement Program, Approved Investment Amount, Year Three														35,000,000
Approved Infrastructure Replacement Program, Approved Investment Amount, Year Four														35,000,000
Approved Infrastructure Replacement Program, Approved Investment Amount, Year Five														35,000,000
Approved Infrastructure Replacement Program, Approved Investment Amount, Year Six														$ 35,000,000
SAFE [Member] | Florida City Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																						10 years
Approved Infrastructure Replacement Program																						$ 105,000,000															$ 105,000,000
energySMART [Member] | Nicor Gas [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Program Duration Period																																3 years
Approved Infrastructure Replacement Program																																$ 93,000,000
Retail [Member] | Mississippi Power [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Under Recovered Fuel Cost				37,000,000														37,000,000						37,000,000		37,000,000				37,000,000
Proposed Change in Annual Revenues				$ 55,000,000														$ 55,000,000						$ 55,000,000		$ 55,000,000				$ 55,000,000
Favorable Regulatory Action [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Gain Contingency, Surcharge Revenue																					15,000,000
Litigation Settlement, Amount																					$ 144,000,000
Gain Contingency, Unrecorded Amount, Alternative Phased-In Increase | $ / item																																																	0.81								0.82
Favorable Regulatory Action [Member] | Scenario, Forecast [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Gain Contingency, Unrecorded Amount, Alternative Phased-In Increase | $ / item																																												0.81
True Up Recovery [Member] | Atlanta Gas Light
Schedule of Regulatory Assets and Liabilities [Line Items]
Gain Contingency, Unrecorded Amount																																																										$ 178,000,000
Interest Expense																															1,000,000
Selling, General and Administrative Expense																															$ 5,000,000

Contingencies and Regulatory 75

Contingencies and Regulatory Matters - Textual - Integrated Coal Gasification Combined Cycle, Kemper, Lignite Mine, Termination of Proposed Sale (Details)	Nov. 17, 2016USD ($)	Jun. 03, 2016	Jan. 28, 2016USD ($)	Dec. 03, 2015USD ($)	Jun. 03, 2015USD ($)	Jan. 01, 2014USD ($)	Mar. 19, 2013	Mar. 31, 2016USD ($)	Jan. 31, 2013USD ($)	Dec. 31, 2016USD ($)mi	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)miMW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2010	Dec. 31, 2016USD ($)mi	Dec. 31, 2016USD ($)mi	Nov. 30, 2016USD ($)	Jun. 17, 2016USD ($)	May 03, 2016USD ($)	Aug. 13, 2015USD ($)	May 20, 2015USD ($)
Loss Contingencies [Line Items]
Estimated loss on Kemper IGCC																		$ 428,000,000	$ 365,000,000	$ 868,000,000
Other Regulatory Assets Deferred										$ 6,851,000,000				$ 4,989,000,000				6,851,000,000	4,989,000,000					$ 6,851,000,000	$ 6,851,000,000
Other Assets, Current										230,000,000				71,000,000				230,000,000	71,000,000					230,000,000	230,000,000
Asset Retirement Obligation										4,514,000,000				3,759,000,000				4,514,000,000	3,759,000,000	2,201,000,000				4,514,000,000	4,514,000,000
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity																		202,000,000	226,000,000	245,000,000
Other Regulatory Assets Current										581,000,000				580,000,000				581,000,000	580,000,000					581,000,000	581,000,000
Mississippi Power [Member]
Loss Contingencies [Line Items]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress										$ 3,670,000,000								3,670,000,000						$ 3,670,000,000	$ 3,670,000,000
Estimated loss on Kemper IGCC																		$ 428,000,000	365,000,000	868,000,000
Plant Capacity Under Coal Gasification Combined Cycle Technology | MW																		582
Co Two Pipeline Infrastructure | mi										61								61						61	61
Costs Related to Grant Funding																						$ 245,000,000
Total Kemper IGCC																						$ 2,880,000,000
Other Property And Investments										$ 6,000,000								$ 6,000,000						$ 6,000,000	$ 6,000,000
Lignite Mining Costs										75,000,000								75,000,000						75,000,000	75,000,000
Materials, Supplies, and Other										47,000,000								47,000,000						47,000,000	47,000,000
Cost Deferred in Other Regulatory Assets										29,000,000								29,000,000						29,000,000	29,000,000
Other Regulatory Assets Deferred										518,000,000				525,000,000				518,000,000	525,000,000					518,000,000	518,000,000
Other Assets, Current										8,000,000				8,000,000				8,000,000	8,000,000					8,000,000	8,000,000
Asset Retirement Obligation										179,000,000				177,000,000				179,000,000	177,000,000	$ 48,000,000				179,000,000	179,000,000
Reduced Percentage Interest Transferred under Asset Purchase Agreement																				15.00%			15.00%
PSC Retail Rate Increase (Decrease)																										$ 1,000,000	$ (1,000,000)	$ (2,000,000)
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
Retail Rate Recovery														342,000,000					371,000,000
Carrying Costs Associated With Retail Rate Recovery														29,000,000
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity																		124,000,000	110,000,000	$ 136,000,000
Other Regulatory Assets Current										115,000,000				95,000,000				115,000,000	95,000,000					115,000,000	115,000,000
Regulatory Liabilities										$ 7,000,000								$ 7,000,000						$ 7,000,000	$ 7,000,000
Term of Management Fee Contract																		40 years
Percentage of Carbon Dioxide Captured from Project										70.00%								70.00%						70.00%	70.00%
Percentage of Contract to Purchase Carbon Dioxide from Project										30.00%								30.00%						30.00%	30.00%
Interest Bearing Refundable Deposit Related to Assets Sale																														$ 275,000,000
Return Of Interest Bearing Refundable Deposits Related to Assets Sale Plus Accrued Interest					$ 301,000,000
Promissory note			$ 275,000,000		$ 301,000,000													$ 0	301,000,000	0
Electricity Generation Plant, Non-Nuclear [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated Cost									$ 2,400,000,000												$ 2,400,000,000
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Pre-Tax Charge To Income										$ 206,000,000	$ 88,000,000	$ 81,000,000	$ 53,000,000	183,000,000	$ 150,000,000	$ 23,000,000	$ 9,000,000
After Tax Charge To Income										127,000,000	54,000,000	50,000,000	33,000,000	113,000,000	93,000,000	14,000,000	6,000,000	264,000,000	226,000,000	536,000,000
Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated loss on Kemper IGCC																									$ 2,840,000,000
Pre-Tax Charge To Income										206,000,000	88,000,000	81,000,000	53,000,000	183,000,000	150,000,000	23,000,000	9,000,000	348,000,000	365,000,000	868,000,000					2,760,000,000
After Tax Charge To Income										$ 127,000,000	$ 54,000,000	$ 50,000,000	$ 33,000,000	$ 113,000,000	$ 93,000,000	$ 14,000,000	$ 6,000,000	$ 215,000,000	$ 226,000,000	536,000,000					$ 1,710,000,000
Purchase of Interest										100.00%								100.00%						100.00%	100.00%
Estimated Cost	$ 68,000,000																	$ 5,440,000,000
Project Improvement Costs										$ 12,000,000								12,000,000						$ 12,000,000	$ 12,000,000
Total Kemper IGCC																		6,730,000,000
Other Regulatory Assets Deferred										172,000,000								172,000,000						172,000,000	172,000,000
Other Assets, Current										3,000,000								3,000,000						3,000,000	3,000,000
Asset Retirement Obligation										14,000,000								14,000,000						14,000,000	14,000,000
Monthly Charge Of Allowance For Equity Funds Used During Construction																		16,000,000
Monthly Cost, Regulatory Assets and Other																		3,000,000
Costs Subject to Cost Cap																		1,990,000,000
Cost Cap Exceptions																		$ 1,460,000,000
Period Of Commercial Operations Established By Discovery Docket																		5 years
Average Annual Increase Decrease in Operations and Maintenance Expenses																		$ 105,000,000
Average Annual Increase Decrease in Maintenance Capital																		44,000,000
Recoverable Cost Above Maximum Cap Construction Cost																		3,310,000,000
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity																								398,000,000
Regulatory asset										97,000,000								97,000,000						97,000,000	97,000,000
Other Regulatory Assets Current										104,000,000								104,000,000						104,000,000	104,000,000
Kemper IGCC [Member] | Parent And Mississippi Power [Member]
Loss Contingencies [Line Items]
Pre-Tax Charge To Income																				868,000,000
After Tax Charge To Income																				$ 536,000,000
Mine [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Term of Management Fee Contract																							40 years
Cost Estimate Extension [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated Cost																		186,000,000
Operational Readiness And Other Post In-Service Costs [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated Cost																		162,000,000
Minimum [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated In-service Capital Cost																		$ 25,000,000
Amortization Period of Regulatory Assets and Liabilities																		2 years
Maximum [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated In-service Capital Cost																		$ 35,000,000
Amortization Period of Regulatory Assets and Liabilities																		10 years
Wholesale [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost, Percent																		29.00%
Retail [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost, Percent																		71.00%
2017 Accounting Order Request [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Monthly Charge Of Allowance For Equity Funds Used During Construction																		$ 11,000,000
Monthly Cost, Regulatory Assets and Other																		25,000,000
2017 Rate Case [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Pre-Tax Charge To Income																		80,000,000
Alternate Financing																					$ 1,000,000,000
In-Service Asset Proposal [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Customer Refund								$ 11,000,000
PSC Retail Rate Increase (Decrease)				$ 126,000,000																									$ 159,000,000
Public Utilities, Approved Equity Capital Structure, Percentage				49.733%
Public Utilities, Approved Return on Equity, Percentage				9.225%
Assets, Current [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Regulatory asset										$ 29,000,000								$ 29,000,000						$ 29,000,000	$ 29,000,000
Denbury Onshore, Contractor [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Long Term Contract For Purchase Of Percentage of Carbon Dioxide Captured from Plant		100.00%
Denbury Onshore, Contractor [Member] | Electricity Generation Plant, Non-Nuclear [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Long-term Contract For Purchase of Carbon Dioxide, Term		16 years

Contingencies and Regulatory 76

Contingencies and Regulatory Matters - Textual - Litigation, Bonus Depreciation, Investment Tax Credits, and Section 174 (Details) - USD ($) $ in Millions	Jun. 09, 2016	Apr. 19, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Unrecognized tax benefits					$ 484		$ 433	$ 170	$ 7
Mississippi Power [Member]
Loss Contingencies [Line Items]
Minimum Percentage of Carbon Dioxide That Must Capture and Sequester to Remain Eligible for Tax Credits		65.00%
Unrecognized tax benefits					465		$ 421	$ 165	$ 4
Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Positive Impact From Bonus Depreciation					20
Internal Revenue Code Section Forty Eight Tax Credits Phase I					133
Internal Revenue Code Section Forty Eight Tax Credits Phase I I					279
Unrecognized tax benefits					$ 464
Scenario, Forecast [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Bonus Depreciation for Property Acquired			30.00%	40.00%		50.00%
Scenario, Forecast [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Positive Impact From Bonus Depreciation						$ 370
Pending Litigation [Member] | Kemper IGCC [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 100

Contingencies and Regulatory 77

Contingencies and Regulatory Matters - Table - Current And Actual Cost Estimate (Details) - Mississippi Power [Member] - USD ($) $ in Millions	Nov. 17, 2016	Apr. 08, 2016	Apr. 01, 2015	Jan. 31, 2013	Dec. 31, 2016	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2016
Loss Contingencies [Line Items]
AFUDC Cost			$ 14
Grants received from Department of Energy								$ (382)
Total Kemper IGCC							$ 2,880
Electricity Generation Plant, Non-Nuclear [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap				$ 2,400		$ 2,400
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					$ 3,310
Plant Subject to Cost Cap	$ 68				5,440
Cost Of Lignite Mine And Equipment					230
Cost Of CO2 Pipeline Facilities					110
Cost Of AFUDC					750
Combined Cycle And Related Assets Placed In Service, Incremental					40
AFUDC Cost			$ 11
Plant General Exceptions					90
Plant Regulatory Asset					210
Grants received from Department of Energy		$ (137)			(140)			$ (245)
Total Kemper IGCC					$ 6,730
Purchase of Interest					100.00%			100.00%
Costs Subject to Cost Cap					$ 1,990
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
Grants received from Department of Energy					0
Total Kemper IGCC					2,970
Kemper IGCC [Member] | Current Estimate [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap					5,640
Cost Of Lignite Mine And Equipment					230
Cost Of CO2 Pipeline Facilities					110
Cost Of AFUDC					790
Combined Cycle And Related Assets Placed In Service, Incremental					40
Plant General Exceptions					100
Plant Regulatory Asset					220
Grants received from Department of Energy					(140)
Total Kemper IGCC					6,990
Costs for Combined Cycle and Related Assets In Service Expensed [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Total Kemper IGCC					830
Current Estimate [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Total Kemper IGCC					250
Gasifiers and Gas Clean-up Facilities [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					1,880
Lignite Mine Facility [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					310
CO2 Pipeline Facilities [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					110
Combined Cycle and Common Facilities [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					160
AFUDC [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					690
General Exceptions [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					70
Plant Inventory [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					30
Lignite Inventory [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					80
Regulatory and Other Deferred Assets [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					120
All Costs [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Recoverable Cost Above Maximum Cap Construction Cost					3,450
Costs Previously Expensed and Related Assets In Service [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Total Kemper IGCC					$ 80

Contingencies and Regulatory 78

Contingencies and Regulatory Matters - Table - Unrecognized Ratemaking Amounts (Details) - Regulatory Asset Off Balance Sheet - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Successor [Member]
Loss Contingencies [Line Items]
Regulatory asset	$ 129
Successor [Member] | Atlanta Gas Light
Loss Contingencies [Line Items]
Regulatory asset	110
Successor [Member] | Virginia Natural Gas
Loss Contingencies [Line Items]
Regulatory asset	11
Successor [Member] | Elizabethtown Gas [Member]
Loss Contingencies [Line Items]
Regulatory asset	6
Successor [Member] | Nicor Gas [Member]
Loss Contingencies [Line Items]
Regulatory asset	$ 2
Predecessor [Member]
Loss Contingencies [Line Items]
Regulatory asset		$ 122
Predecessor [Member] | Atlanta Gas Light
Loss Contingencies [Line Items]
Regulatory asset		103
Predecessor [Member] | Virginia Natural Gas
Loss Contingencies [Line Items]
Regulatory asset		12
Predecessor [Member] | Elizabethtown Gas [Member]
Loss Contingencies [Line Items]
Regulatory asset		4
Predecessor [Member] | Nicor Gas [Member]
Loss Contingencies [Line Items]
Regulatory asset		$ 3

Joint Ownership Agreements (Det

Joint Ownership Agreements (Details) $ in Millions	Dec. 31, 2016USD ($)MW	Aug. 31, 2016
Alabama Power [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	1,000
Company Ownership	14.00%
Alabama Power [Member] | Plant Miller (coal) Units 1 and 2 [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	1,320
Company Ownership	91.84%
Plant in service	$ 1,657
Accumulated depreciation	587
Construction Work in Progress	$ 23
Alabama Power [Member] | Greene County [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	500
Company Ownership	60.00%
Plant in service	$ 168
Accumulated depreciation	66
Construction Work in Progress	$ 1
Alabama Power [Member] | SEGCO [Member]
Jointly owned utility plant interests
Company Ownership	86.00%
Georgia Power [Member] | Plant Vogtle Nuclear Units One and Two [Member]
Jointly owned utility plant interests
Company Ownership	45.70%
Plant in service	$ 3,545
Accumulated depreciation	2,111
Construction Work in Progress	$ 74
Georgia Power [Member] | Plant Hatch (nuclear) [Member]
Jointly owned utility plant interests
Company Ownership	50.10%
Plant in service	$ 1,297
Accumulated depreciation	585
Construction Work in Progress	$ 81
Georgia Power [Member] | Plant Scherer (coal) Units 1 and 2 [Member]
Jointly owned utility plant interests
Company Ownership	8.40%
Plant in service	$ 258
Accumulated depreciation	90
Construction Work in Progress	$ 3
Georgia Power [Member] | Plant Wansley (coal) [Member]
Jointly owned utility plant interests
Company Ownership	53.50%
Plant in service	$ 1,046
Accumulated depreciation	308
Construction Work in Progress	$ 12
Georgia Power [Member] | Rocky Mountain (pumped storage) [Member]
Jointly owned utility plant interests
Company Ownership	25.40%
Plant in service	$ 181
Accumulated depreciation	129
Construction Work in Progress	$ 0
Georgia Power [Member] | Plant Scherer Unit 3 (coal) [Member]
Jointly owned utility plant interests
Company Ownership	75.00%
Plant in service	$ 1,203
Accumulated depreciation	458
Construction Work in Progress	$ 23
Georgia Power [Member] | Intercession City (combustion turbine) [Member]
Jointly owned utility plant interests
Company Ownership		33.00%
Georgia Power [Member] | Vogtle Units 3 and 4 [Member]
Jointly owned utility plant interests
Company Ownership	45.70%
Gulf Power [Member] | Plant Scherer Unit 3 (coal) [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	818
Company Ownership	25.00%
Plant in service	$ 398
Accumulated depreciation	143
Construction Work in Progress	$ 7
Gulf Power [Member] | Plant Daniel Units 1 and 2 [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	1,000
Company Ownership	50.00%
Plant in service	$ 680
Accumulated depreciation	202
Construction Work in Progress	$ 7
Mississippi Power [Member] | Plant Daniel Units 1 and 2 [Member]
Jointly owned utility plant interests
Company Ownership	50.00%
Southern Power [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	659
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member]
Jointly owned utility plant interests
Company Ownership	65.00%
Plant in service	$ 155
Accumulated depreciation	58
Construction Work in Progress	$ 0
Gulf Power [Member] | Mississippi Power [Member] | Plant Daniel Units 1 and 2 [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	1,000
Company Ownership	50.00%
Plant in service	$ 695
Accumulated depreciation	173
Construction Work in Progress	$ 15
Alabama Power [Member] | Mississippi Power [Member] | Greene County [Member]
Jointly owned utility plant interests
Total megawatt capacity | MW	500
Company Ownership	40.00%
Plant in service	$ 165
Accumulated depreciation	48
Construction Work in Progress	$ 0

Joint Ownership Agreements - Eq

Joint Ownership Agreements - Equity Method Investments - Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	$ 1,549	$ 6
Successor [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	1,541
Successor [Member] | SNG [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	1,394
Current assets	95
Property, plant, and equipment	2,451
Deferred charges and other assets	129
Total Assets	2,675
Current liabilities	588
Long-term debt	706
Other deferred charges and other liabilities	22
Total Liabilities	1,316
Total Stockholders' Equity	1,359
Total Liabilities and Stockholders' Equity	2,675
Successor [Member] | Triton [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	44
Successor [Member] | Horizon Pipeline [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	30
Successor [Member] | PennEast Pipeline [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	22
Successor [Member] | Atlantic Coast Pipeline [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	33
Successor [Member] | Pivotal JAX LNG, LLC [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	16
Successor [Member] | Other [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	$ 2
Predecessor [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		80
Predecessor [Member] | SNG [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		0
Predecessor [Member] | Triton [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		49
Predecessor [Member] | Horizon Pipeline [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		14
Predecessor [Member] | PennEast Pipeline [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		9
Predecessor [Member] | Atlantic Coast Pipeline [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		7
Predecessor [Member] | Pivotal JAX LNG, LLC [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		0
Predecessor [Member] | Other [Member] | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		$ 1

Joint Ownership Agreements - 81

Joint Ownership Agreements - Equity Method Investments - Income Statement Information (Details) - USD ($) $ in Millions	4 Months Ended	6 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Jun. 30, 2016	Oct. 03, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments				$ 15	$ 59	$ 0	$ 0
Southern Company Gas [Member] | Successor [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments		$ 60
Southern Company Gas [Member] | Successor [Member] | SNG [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments		56
Revenues	$ 230
Operating income	138
Net income	$ 115
Southern Company Gas [Member] | Successor [Member] | Triton [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments		2
Southern Company Gas [Member] | Successor [Member] | Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments		1
Southern Company Gas [Member] | Successor [Member] | Atlantic Coast Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments		$ 1
Southern Company Gas [Member] | Predecessor [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			$ 2			6	8
Southern Company Gas [Member] | Predecessor [Member] | SNG [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			0			0	0
Southern Company Gas [Member] | Predecessor [Member] | Triton [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			1			4	6
Southern Company Gas [Member] | Predecessor [Member] | Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			1			2	2
Southern Company Gas [Member] | Predecessor [Member] | Atlantic Coast Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			$ 0			$ 0	$ 0

Joint Ownership Agreements - Re

Joint Ownership Agreements - Redeemable Noncontrolling Interest Roll Forward (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance		$ 43	$ 43
Net income attributable to noncontrolling interests			36	$ 14	$ 0
Distributions to noncontrolling interests			(72)	(18)	(1)
Ending balance	$ 164		164	43
Southern Company Gas [Member] | Predecessor [Member]
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	41	0	0
Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest		46
Net income attributable to noncontrolling interests		14		20	18
Distributions to noncontrolling interests		(19)		(18)	$ (17)
Ending balance		41		$ 0
Southern Company Gas [Member] | Successor [Member]
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	174
Net income attributable to noncontrolling interests	0
Distributions to noncontrolling interests	(15)
Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable noncontrolling interest	(174)
Ending balance	$ 0	$ 174	$ 0

Joint Ownership Agreements - Na

Joint Ownership Agreements - Narrative (Details) gal in Thousands	6 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)miMW	Jun. 30, 2016USD ($)	Oct. 03, 2016USD ($)	Dec. 31, 2016USD ($)miMWgal	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)miBcf	Dec. 31, 2008	Oct. 02, 2016	Sep. 01, 2016	Aug. 31, 2016	Feb. 12, 2016USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress	$ 8,977,000,000			$ 8,977,000,000	$ 9,082,000,000
Short-term debt	2,241,000,000			2,241,000,000	1,376,000,000
Earnings from equity method investments			$ 15,000,000	59,000,000	0	$ 0
Distributions to noncontrolling interests				72,000,000	18,000,000	1,000,000
Southern Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress	$ 398,000,000			$ 398,000,000	1,137,000,000
Total megawatt capacity | MW	659			659
Short-term debt	$ 209,000,000			$ 209,000,000	137,000,000
Distributions to noncontrolling interests				$ 57,000,000	18,000,000	1,000,000
Southern Power [Member] | Plant Stanton Combined Cycle Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	65.00%			65.00%
Plant in service	$ 155,000,000			$ 155,000,000
Accumulated depreciation	58,000,000			58,000,000
Gulf Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress	51,000,000			51,000,000	48,000,000
Short-term debt	$ 268,000,000			$ 268,000,000	142,000,000
Gulf Power [Member] | Plant Daniel Units 1 and 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total megawatt capacity | MW	1,000			1,000
Percent ownership	50.00%			50.00%
Plant in service	$ 680,000,000			$ 680,000,000
Accumulated depreciation	$ 202,000,000			$ 202,000,000
Gulf Power [Member] | Plant Scherer Unit Three [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total megawatt capacity | MW	818			818
Percent ownership	25.00%			25.00%
Plant in service	$ 398,000,000			$ 398,000,000
Accumulated depreciation	143,000,000			143,000,000
Georgia Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage of proportionate share owed in consortium agreement							45.70%
Construction work in progress	4,939,000,000			4,939,000,000	4,775,000,000
Short-term debt	$ 391,000,000			$ 391,000,000	158,000,000
Georgia Power [Member] | Alabama Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total megawatt capacity | MW	1,020			1,020
Georgia Power [Member] | Intercession City Combustion Turbine [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership										33.00%
Georgia Power [Member] | Vogtle Units Three and Four [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	45.70%			45.70%
Georgia Power [Member] | Plant Scherer Unit Three [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	75.00%			75.00%
Plant in service	$ 1,203,000,000			$ 1,203,000,000
Accumulated depreciation	458,000,000			458,000,000
Georgia Power [Member] | Southern Electric Generating Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Share Of purchased power				57,000,000	78,000,000
Alabama Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress	$ 491,000,000			$ 491,000,000	801,000,000
Total megawatt capacity | MW	1,000			1,000
Jointly owned affiliate equity				$ 108,000,000
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	0
Ownership percentage, equity method investment	50.00%			50.00%
Percent ownership	14.00%			14.00%
Alabama Power [Member] | SEGCO [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	86.00%			86.00%
Alabama Power [Member] | Southern Electric Generating Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total megawatt capacity | MW	1,020			1,020
Share Of purchased power				$ 55,000,000	76,000,000	84,000,000
Unconditional guarantee to pay outstanding pollution control revenue bond principal	$ 25,000,000			25,000,000
Alabama Power [Member] | SEGCO [Member]
Jointly Owned Utility Plant Interests [Line Items]
Short-term debt	$ 38,000,000			38,000,000
Dividends paid by equity method investment				$ 24,000,000
Southern Company Gas [Member] | Dalton Pipeline [Member]
Jointly Owned Utility Plant Interests [Line Items]
Costs included in CWIP					$ 33,000,000
Undivided ownership interest to be leased				50.00%	50.00%
Pipeline infrastructure | mi	115			115
Southern Company Gas [Member] | Dalton Pipeline Arrangement 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Undivided ownership interest to be leased				50.00%
Future minimum payments receivable	$ 26,000,000			$ 26,000,000
Term of contract				25 years
Maturity December First Two Thousand Eighteen [Member] | Alabama Power [Member] | Southern Electric Generating Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Guarantee of unsecured senior notes	100,000,000			$ 100,000,000
Plant Vogtle Units 3 And 4 [Member] | Georgia Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress	$ 3,900,000,000			$ 3,900,000,000
Dalton Pipeline Arrangement 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage of voting interests acquired	50.00%			50.00%
Successor [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress	$ 496,000,000			$ 496,000,000
Short-term debt	1,257,000,000			1,257,000,000
Earnings from equity method investments	60,000,000
Distributions to noncontrolling interests	15,000,000
Successor [Member] | Southern Company Gas [Member] | Dalton Pipeline [Member]
Jointly Owned Utility Plant Interests [Line Items]
Costs included in CWIP	$ 124,000,000			$ 124,000,000
Predecessor [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Construction work in progress					$ 414,000,000
Short-term debt					1,010,000,000
Earnings from equity method investments		$ 2,000,000			6,000,000	8,000,000
Distributions to noncontrolling interests		19,000,000			$ 18,000,000	17,000,000
Purchased Power from Affiliates [Member] | Georgia Power [Member] | Southern Electric Generating Company [Member]
Jointly Owned Utility Plant Interests [Line Items]
Share Of purchased power						84,000,000
Orlando Utilities Commission [Member] | Southern Power [Member] | Plant Stanton Combined Cycle Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	28.00%			28.00%
Florida Municipal Power Agency [Member] | Southern Power [Member] | Plant Stanton Combined Cycle Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	3.50%			3.50%
Kissimmee Utility Authority [Member] | Southern Power [Member] | Plant Stanton Combined Cycle Unit [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percent ownership	3.50%			3.50%
Southstar [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage of noncontrolling interest								85.00%
Agreement to purchase remaining interest			$ 160,000,000								$ 160,000,000
Southstar [Member] | Piedmont [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage of noncontrolling interest								15.00%
Georgia Natural Gas [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Noncontrolling ownership percentage held by parent					100.00%
Piedmont [Member] | Southstar [Member]
Jointly Owned Utility Plant Interests [Line Items]
Payments of ordinary dividends to noncontrolling interests	$ 15,000,000
Piedmont [Member] | Southstar [Member] | Predecessor [Member]
Jointly Owned Utility Plant Interests [Line Items]
Distributions to noncontrolling interests		19,000,000			$ 18,000,000	17,000,000
Southern Natural Gas Company, LLC [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage, equity method investment									50.00%
Horizon Pipeline [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Pipeline infrastructure | mi	70			70
Horizon Pipeline [Member] | Successor [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Earnings from equity method investments	$ 1,000,000
Horizon Pipeline [Member] | Predecessor [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Earnings from equity method investments		1,000,000			2,000,000	$ 2,000,000
PennEast Pipeline [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage, equity method investment						20.00%
Pipeline infrastructure | mi						118
Atlantic Coast Pipeline [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage, equity method investment						5.00%
Pipeline infrastructure | mi						594
Atlantic Coast Pipeline [Member] | Successor [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Earnings from equity method investments	$ 1,000,000
Atlantic Coast Pipeline [Member] | Predecessor [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Earnings from equity method investments		$ 0			$ 0	$ 0
Pivotal JAX LNG, LLC [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentage, equity method investment	50.00%			50.00%
Minimum [Member] | Horizon Pipeline [Member] | Nicor Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Capacity of Natural Gas Facility, Percent	70.00%			70.00%
Minimum [Member] | PennEast Pipeline [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Natural Gas Pipeline Capacity (Volume) | Bcf						1
Minimum [Member] | Atlantic Coast Pipeline [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Natural Gas Pipeline Capacity (Volume) | Bcf						1.5
Maximum [Member] | Horizon Pipeline [Member] | Nicor Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Capacity of Natural Gas Facility, Percent	80.00%			80.00%
Liquefied Natural Gas (LNG) [Member] | Pivotal JAX LNG, LLC [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Storage facility capacity | gal				2,000
Liquefied Natural Gas (LNG) [Member] | Minimum [Member] | Pivotal JAX LNG, LLC [Member] | Southern Company Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Storage facility production capacity | gal				120

Income Taxes - Current and Defe

Income Taxes - Current and Deferred Income Tax Provisions (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Federal -
Current			$ 1,184	$ (177)	$ 175
Deferred			(342)	1,266	695
Total federal taxes			842	1,089	870
State -
Current			(108)	(33)	93
Deferred			217	138	14
Total state taxes			109	105	107
Income taxes			951	1,194	977
Deferred income tax assets	$ 9,495		9,495	6,683
Alabama Power [Member]
Federal -
Current			103	110	198
Deferred			339	320	225
Total federal taxes			442	430	423
State -
Current			20	8	44
Deferred			69	68	45
Total state taxes			89	76	89
Income taxes			531	506	512
Deferred income tax assets	1,544		1,544	1,511
Georgia Power [Member]
Federal -
Current			391	515	295
Deferred			319	176	366
Total federal taxes			710	691	661
State -
Current			6	81	82
Deferred			64	(3)	(14)
Total state taxes			70	78	68
Income taxes			780	769	729
Deferred income tax assets	2,382		2,382	2,077
Gulf Power [Member]
Federal -
Current			34	(3)	23
Deferred			45	80	52
Total federal taxes			79	77	75
State -
Current			0	5	0
Deferred			12	10	13
Total state taxes			12	15	13
Income taxes			91	92	88
Deferred income tax assets	244		244	216
Mississippi Power [Member]
Federal -
Current			(31)	(768)	(431)
Deferred			(60)	704	183
Total federal taxes			(91)	(64)	(248)
State -
Current			(6)	(81)	1
Deferred			(7)	73	(38)
Total state taxes			(13)	(8)	(37)
Income taxes			(104)	(72)	(285)
Deferred income tax assets	1,024		1,024	1,400
Southern Power [Member]
Federal -
Current			928	12	179
Deferred			(1,098)	10	(166)
Total federal taxes			(170)	22	13
State -
Current			(60)	(32)	(14)
Deferred			35	31	(2)
Total state taxes			(25)	(1)	(16)
Income taxes			(195)	21	(3)
Deferred income tax assets	2,937		2,937	794
Southern Power [Member] | Unrealized Tax Credits [Member]
State -
Deferred income tax assets	1,685		1,685	551
Southern Power [Member] | Deferred Charges Related To Income Taxes, Current [Member] | Other Noncurrent Assets [Member] | Unrealized Tax Credits [Member]
State -
Deferred income tax assets	1,130		1,130	246	305
Successor [Member] | Southern Company Gas [Member]
Federal -
Current	0
Deferred	65
Total federal taxes	65
State -
Current	(16)
Deferred	27
Total state taxes	11
Income taxes	76
Deferred income tax assets	$ 598		$ 598
Predecessor [Member] | Southern Company Gas [Member]
Federal -
Current		$ 67		(13)	111
Deferred		8		198	184
Total federal taxes		75		185	295
State -
Current		12		10	38
Deferred		0		18	17
Total state taxes		12		28	55
Income taxes		$ 87		213	$ 350
Deferred income tax assets				$ 438

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Deferred tax liabilities -
Deferred income tax liabilities	$ 23,512	$ 18,945
Deferred tax assets -
Deferred income tax assets	9,495	6,683
Valuation allowance	(23)	(4)
Total deferred tax liabilities, net	14,040	12,266
Accumulated deferred income taxes – assets	52	56
Accumulated deferred income taxes – liability	14,092	12,322
Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	15,392	12,767
Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	2,708	1,603
Leveraged lease basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	314	308
Employee benefit obligations
Deferred tax liabilities -
Deferred income tax liabilities	737	579
Deferred tax assets -
Deferred income tax assets	1,868	1,720
Premium on reacquired debt [Member]
Deferred tax liabilities -
Deferred income tax liabilities	89	95
Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	1,584	1,378
Regulatory assets associated with asset retirement obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	1,781	1,422
Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	907	793
Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	597	479
Over recovered fuel clause [Member]
Deferred tax assets -
Deferred income tax assets	66	104
Other property basis differences [Member]
Deferred tax assets -
Deferred income tax assets	401	695
Deferred costs [Member]
Deferred tax assets -
Deferred income tax assets	100	83
Investment Tax Credit Carryforward [Member]
Deferred tax assets -
Deferred income tax assets	1,974	770
Federal NOL Carryforward [Member]
Deferred tax assets -
Deferred income tax assets	1,084	38
Unbilled revenues [Member]
Deferred tax assets -
Deferred income tax assets	92	111
Other Comprehensive Income Losses [Member]
Deferred tax assets -
Deferred income tax assets	152	85
Asset retirement obligations
Deferred tax assets -
Deferred income tax assets	1,732	1,482
Kemper IGCC Loss [Member]
Deferred tax assets -
Deferred income tax assets	484	451
Deferred State Tax Assets [Member]
Deferred tax assets -
Deferred income tax assets	266	222
Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	679	443
Alabama Power [Member]
Deferred tax liabilities -
Deferred income tax liabilities	6,198	5,752
Deferred tax assets -
Deferred income tax assets	1,544	1,511
Total deferred tax liabilities, net	4,654	4,241
Accumulated deferred income taxes – liability	4,654	4,241
Alabama Power [Member] | Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	4,307	3,917
Alabama Power [Member] | Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	456	456
Alabama Power [Member] | Leveraged lease basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	26	28
Alabama Power [Member] | Employee benefit obligations
Deferred tax liabilities -
Deferred income tax liabilities	201	200
Deferred tax assets -
Deferred income tax assets	427	407
Alabama Power [Member] | Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	393	375
Alabama Power [Member] | Regulatory assets associated with asset retirement obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	347	312
Alabama Power [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	179	175
Alabama Power [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	266	242
Alabama Power [Member] | Unbilled revenues [Member]
Deferred tax assets -
Deferred income tax assets	36	39
Alabama Power [Member] | Other Comprehensive Income Losses [Member]
Deferred tax assets -
Deferred income tax assets	19	20
Alabama Power [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	139	180
Alabama Power [Member] | Asset retirement obligation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	289	289
Deferred tax assets -
Deferred income tax assets	636	600
Alabama Power [Member] | Storm damage reserves
Deferred tax assets -
Deferred income tax assets	21	23
Georgia Power [Member]
Deferred tax liabilities -
Deferred income tax liabilities	8,382	7,704
Deferred tax assets -
Deferred income tax assets	2,382	2,077
Total deferred tax liabilities, net	6,000	5,627
Accumulated deferred income taxes – liability	6,000	5,627
Georgia Power [Member] | Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	5,266	4,909
Georgia Power [Member] | Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	957	1,003
Georgia Power [Member] | Employee benefit obligations
Deferred tax liabilities -
Deferred income tax liabilities	428	310
Deferred tax assets -
Deferred income tax assets	661	642
Georgia Power [Member] | Premium on reacquired debt [Member]
Deferred tax liabilities -
Deferred income tax liabilities	56	61
Georgia Power [Member] | Regulatory Assets Associated With Storm Damage Reserves [Member]
Deferred tax liabilities -
Deferred income tax liabilities	83	37
Georgia Power [Member] | Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	546	528
Georgia Power [Member] | Regulatory Assets Associated With Retired Assets [Member]
Deferred tax liabilities -
Deferred income tax liabilities	55	58
Georgia Power [Member] | Regulatory assets associated with asset retirement obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	726	545
Georgia Power [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	83	92
Georgia Power [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	173	150
Georgia Power [Member] | Other property basis differences [Member]
Deferred tax assets -
Deferred income tax assets	105	88
Georgia Power [Member] | Deferred costs [Member]
Deferred tax assets -
Deferred income tax assets	100	83
Georgia Power [Member] | Unbilled revenues [Member]
Deferred tax assets -
Deferred income tax assets	47	47
Georgia Power [Member] | Regulatory Liabilities Associated With Asset Retirement Obligations [Member]
Deferred tax assets -
Deferred income tax assets	33	60
Georgia Power [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	70	82
Georgia Power [Member] | Asset retirement obligation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	182	161
Deferred tax assets -
Deferred income tax assets	908	706
Georgia Power [Member] | Tax credit carryforward [Member]
Deferred tax assets -
Deferred income tax assets	201	216
Georgia Power [Member] | Federal Tax Credit Carryforward [Member]
Deferred tax assets -
Deferred income tax assets	84	3
Gulf Power [Member]
Deferred tax liabilities -
Deferred income tax liabilities	1,192	1,109
Deferred tax assets -
Deferred income tax assets	244	216
Total deferred tax liabilities, net	948	893
Accumulated deferred income taxes – liability	948	893
Gulf Power [Member] | Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	834	812
Gulf Power [Member] | Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	123	133
Gulf Power [Member] | Employee benefit obligations
Deferred tax liabilities -
Deferred income tax liabilities	58	39
Gulf Power [Member] | Regulatory Assets [Member]
Deferred tax liabilities -
Deferred income tax liabilities	45	16
Gulf Power [Member] | Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	65	59
Gulf Power [Member] | Regulatory assets associated with asset retirement obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	55	40
Gulf Power [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	12	10
Gulf Power [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	37	33
Gulf Power [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	19	19
Gulf Power [Member] | Pension and other employee benefits [Member]
Deferred tax assets -
Deferred income tax assets	72	65
Gulf Power [Member] | Asset retirement obligation [Member]
Deferred tax assets -
Deferred income tax assets	55	40
Gulf Power [Member] | Other postretirement benefit plans
Deferred tax assets -
Deferred income tax assets	26	26
Gulf Power [Member] | Tax credit carryforward [Member]
Deferred tax assets -
Deferred income tax assets	18	18
Gulf Power [Member] | Property damage reserves-liability
Deferred tax assets -
Deferred income tax assets	17	15
Mississippi Power [Member]
Deferred tax liabilities -
Deferred income tax liabilities	1,780	2,162
Deferred tax assets -
Deferred income tax assets	1,024	1,400
Total deferred tax liabilities, net	756	762
Accumulated deferred income taxes – liability	756	762
Mississippi Power [Member] | Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	386	1,618
Mississippi Power [Member] | Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	852	0
Deferred tax assets -
Deferred income tax assets	0	451
Mississippi Power [Member] | Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	70	66
Mississippi Power [Member] | Regulatory assets associated with asset retirement obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	72	71
Mississippi Power [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	125	176
Mississippi Power [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	19	8
Mississippi Power [Member] | Over recovered fuel clause [Member]
Deferred tax assets -
Deferred income tax assets	26	51
Mississippi Power [Member] | Kemper IGCC Loss [Member]
Deferred tax assets -
Deferred income tax assets	484	451
Mississippi Power [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	33	33
Mississippi Power [Member] | NOL State Carryforward [Member]
Deferred tax assets -
Deferred income tax assets	113	152
Mississippi Power [Member] | Deferred Federal Tax Assets [Member]
Deferred tax assets -
Deferred income tax assets	31	31
Mississippi Power [Member] | Pension and other employee benefits [Member]
Deferred tax liabilities -
Deferred income tax liabilities	49	30
Deferred tax assets -
Deferred income tax assets	96	92
Mississippi Power [Member] | Federal NOL [Member]
Deferred tax assets -
Deferred income tax assets	109	17
Mississippi Power [Member] | Kemper IGCC
Deferred tax liabilities -
Deferred income tax liabilities	82	86
Mississippi Power [Member] | Asset retirement obligation [Member]
Deferred tax assets -
Deferred income tax assets	72	71
Mississippi Power [Member] | Rate Differential [Member]
Deferred tax liabilities -
Deferred income tax liabilities	144	115
Mississippi Power [Member] | Property insurance [Member]
Deferred tax assets -
Deferred income tax assets	27	25
Mississippi Power [Member] | Premium on long-term debt [Member]
Deferred tax assets -
Deferred income tax assets	14	18
Southern Power [Member]
Deferred tax liabilities -
Deferred income tax liabilities	2,495	1,393
Deferred tax assets -
Deferred income tax assets	2,937	794
Valuation allowance	0	(2)
Total deferred tax liabilities, net		601
Net deferred income tax assets	2,937	792
Deferred tax assets, net	442
Accumulated deferred income taxes – assets	594	0
Accumulated deferred income taxes – liability	152	601
Southern Power [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	27	7
Southern Power [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	53	40
Southern Power [Member] | Investment Tax Credit Carryforward [Member]
Deferred tax assets -
Deferred income tax assets	292	149
Southern Power [Member] | Deferred State Tax Assets [Member]
Deferred tax assets -
Deferred income tax assets	60	13
Southern Power [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	8	14
Southern Power [Member] | Accelerated depreciation and other property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	2,440	1,364
Southern Power [Member] | Levelized capacity revenues [Member]
Deferred tax liabilities -
Deferred income tax liabilities	28	22
Southern Power [Member] | Tax credit carryforward [Member]
Deferred tax assets -
Deferred income tax assets	15	15
Southern Power [Member] | Unrealized Tax Credits [Member]
Deferred tax assets -
Deferred income tax assets	1,685	551
Southern Power [Member] | Federal Net Operating Loss [Member]
Deferred tax assets -
Deferred income tax assets	808	9
Southern Power [Member] | Investment In Partnerships [Member]
Deferred tax assets -
Deferred income tax assets	16	3
Successor [Member] | Southern Company Gas [Member]
Deferred tax liabilities -
Deferred income tax liabilities	2,554
Deferred tax assets -
Deferred income tax assets	598
Valuation allowance	(19)
Total deferred tax liabilities, net	1,975
Net deferred income tax assets	579
Accumulated deferred income taxes – liability	1,975
Successor [Member] | Southern Company Gas [Member] | Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities	1,954
Successor [Member] | Southern Company Gas [Member] | Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities	311
Successor [Member] | Southern Company Gas [Member] | Employee benefit obligations
Deferred tax assets -
Deferred income tax assets	165
Successor [Member] | Southern Company Gas [Member] | Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities	125
Successor [Member] | Southern Company Gas [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities	164
Successor [Member] | Southern Company Gas [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets	42
Successor [Member] | Southern Company Gas [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets	332
Successor [Member] | Southern Company Gas [Member] | Federal NOL [Member]
Deferred tax assets -
Deferred income tax assets	$ 59
Predecessor [Member] | Southern Company Gas [Member]
Deferred tax liabilities -
Deferred income tax liabilities		2,362
Deferred tax assets -
Deferred income tax assets		438
Valuation allowance		(19)
Total deferred tax liabilities, net		1,943
Net deferred income tax assets		419
Accumulated deferred income taxes – liability		1,912
Predecessor [Member] | Southern Company Gas [Member] | Accelerated depreciation [Member]
Deferred tax liabilities -
Deferred income tax liabilities		1,820
Predecessor [Member] | Southern Company Gas [Member] | Property basis differences [Member]
Deferred tax liabilities -
Deferred income tax liabilities		283
Predecessor [Member] | Southern Company Gas [Member] | Employee benefit obligations
Deferred tax assets -
Deferred income tax assets		164
Predecessor [Member] | Southern Company Gas [Member] | Regulatory assets associated with employee benefit obligations [Member]
Deferred tax liabilities -
Deferred income tax liabilities		44
Predecessor [Member] | Southern Company Gas [Member] | Other deferred tax liabilities [Member]
Deferred tax liabilities -
Deferred income tax liabilities		215
Predecessor [Member] | Southern Company Gas [Member] | Federal effect of state deferred taxes [Member]
Deferred tax assets -
Deferred income tax assets		62
Predecessor [Member] | Southern Company Gas [Member] | Other deferred tax assets [Member]
Deferred tax assets -
Deferred income tax assets		212
Predecessor [Member] | Southern Company Gas [Member] | Federal NOL [Member]
Deferred tax assets -
Deferred income tax assets		$ 0

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Federal Statutory Income Tax Rate (Details)	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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			2.10%	1.90%	2.30%
Employee stock plans dividend deduction			(1.20%)	(1.20%)	(1.40%)
Non-deductible book depreciation			0.90%	1.20%	1.40%
AFUDC-Equity			(2.00%)	(2.20%)	(2.90%)
Amortization of ITC			(0.90%)	(0.50%)	(0.50%)
ITC basis difference			(5.00%)	(1.50%)	(1.60%)
Production tax credits			(1.20%)	(0.00%)	(0.00%)
Other			(0.40%)	0.20%	0.20%
Effective income tax rate			27.30%	32.90%	32.50%
Alabama Power [Member]
Reconciliation of federal statutory income tax rate to effective income tax rate
Federal statutory rate			35.00%	35.00%	35.00%
State income tax, net of federal deduction			4.20%	3.80%	4.40%
Non-deductible book depreciation			1.00%	1.20%	1.10%
AFUDC-Equity			(0.70%)	(1.60%)	(1.30%)
Other			(0.70%)	0.00%	(0.20%)
Effective income tax rate			38.80%	38.40%	39.00%
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			2.10%	2.50%	2.20%
Non-deductible book depreciation			0.80%	1.20%	1.30%
AFUDC-Equity			(0.80%)	(0.70%)	(0.80%)
Other			(0.40%)	(0.40%)	(0.70%)
Effective income tax rate			36.70%	37.60%	37.00%
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			3.40%	3.90%	3.50%
Non-deductible book depreciation			0.60%	0.50%	0.40%
Difference in prior years' deferred and current tax rate			(0.10%)	(0.10%)	(0.10%)
AFUDC-Equity			(0.00%)	(1.80%)	(1.80%)
Other			0.60%	(0.60%)	0.10%
Effective income tax rate			39.50%	36.90%	37.10%
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			5.70%	6.30%	4.00%
Non-deductible book depreciation			(0.70%)	(1.30%)	(0.10%)
AFUDC-Equity			28.50%	49.60%	7.80%
Other			0.00%	2.90%	(0.10%)
Effective income tax rate			68.50%	92.50%	46.60%
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			(9.10%)	(0.30%)	(6.00%)
Amortization of ITC			(20.60%)	(5.00%)	(4.30%)
ITC basis difference			(89.00%)	(21.50%)	(27.70%)
Production tax credits			(23.30%)	(0.60%)	(0.00%)
Noncontrolling interests			(6.20%)	(1.70%)	(0.30%)
Other			4.60%	2.50%	1.40%
Effective income tax rate			(108.60%)	8.40%	(1.90%)
Successor [Member] | Southern Company Gas [Member]
Reconciliation of federal statutory income tax rate to effective income tax rate
Federal statutory rate	35.00%
State income tax, net of federal deduction	4.00%
Other	1.00%
Effective income tax rate	40.00%
Predecessor [Member] | Southern Company Gas [Member]
Reconciliation of federal statutory income tax rate to effective income tax rate
Federal statutory rate		35.00%		35.00%	35.00%
State income tax, net of federal deduction		3.50%		3.40%	3.80%
Other		(0.90%)		(2.00%)	(1.20%)
Effective income tax rate		37.60%		36.40%	37.60%

Income Taxes - Changes in Unrec

Income Taxes - Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits at beginning of year	$ 433	$ 170	$ 7
Tax positions increase from current periods	45	43	64
Tax positions increase from prior periods	21	240	102
Tax positions decrease from prior periods	(15)	(20)	(3)
Unrecognized tax benefits at end of year	484	433	170
Mississippi Power [Member]
Changes in unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits at beginning of year	421	165	4
Tax positions increase from current periods	26	32	58
Tax positions increase from prior periods	18	224	103
Unrecognized tax benefits at end of year	465	421	165
Southern Power [Member]
Changes in unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits at beginning of year	8	5	2
Tax positions increase from current periods	17	9	5
Tax positions decrease from prior periods	(8)	(6)	(2)
Unrecognized tax benefits at end of year	$ 17	$ 8	$ 5

Income Taxes - Impact of Unreco

Income Taxes - Impact of Unrecognized Tax Benefits on Effective Tax Rate, If Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impact on effective tax rate
Tax positions impacting the effective tax rate	$ 20	$ 10	$ 10
Tax positions not impacting the effective tax rate	464	423	160
Balance of unrecognized tax benefits	484	433	170	$ 7
Mississippi Power [Member]
Impact on effective tax rate
Tax positions impacting the effective tax rate	1	(2)	4
Tax positions not impacting the effective tax rate	464	423	161
Balance of unrecognized tax benefits	$ 465	$ 421	$ 165	$ 4

Income Taxes - Accrued Interest

Income Taxes - Accrued Interest for Unrecognized Tax Benefits (Details) - Mississippi Power [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward]
Interest accrued at beginning of year	$ 13	$ 3	$ 1
Interest accrued during the period	15	10	2
Balance at end of year	$ 28	$ 13	$ 3

Income Taxes - Textual (Details

Income Taxes - Textual (Details) - USD ($)	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes			$ (148,000,000)	$ (9,000,000)	$ 272,000,000
Tax regulatory assets	$ 1,600,000,000		1,600,000,000
Tax regulatory liabilities	219,000,000		219,000,000
Amortization of deferred investment tax credits			22,000,000	21,000,000	22,000,000
Tax credit carryforward	1,800,000,000		1,800,000,000
State investment tax credit			202,000,000
Tax positions not impacting the effective tax rate	464,000,000		$ 464,000,000	423,000,000	160,000,000
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern			12 months
Unrecognized tax benefits	484,000,000		$ 484,000,000	433,000,000	170,000,000	$ 7,000,000
Net operating loss carryforward	3,000,000,000		3,000,000,000
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward	203,000,000		203,000,000
Deferred tax assets	9,495,000,000		9,495,000,000	6,683,000,000
Investment Tax Credit Carryforward [Member]
Income Tax Disclosure [Line Items]
Deferred tax assets	1,974,000,000		1,974,000,000	770,000,000
Mississippi Power [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes			(97,000,000)	(33,000,000)	(379,000,000)
Tax regulatory assets	362,000,000		362,000,000
Tax regulatory liabilities	7,000,000		7,000,000
Amortization of deferred investment tax credits			1,000,000	1,000,000	1,000,000
Tax positions not impacting the effective tax rate	464,000,000		464,000,000	423,000,000	161,000,000
Unrecognized tax benefits	465,000,000		465,000,000	421,000,000	165,000,000	4,000,000
Interest accrued during the period			15,000,000	10,000,000	2,000,000
Net operating loss carryforward	3,000,000,000		3,000,000,000
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward	112,000,000		112,000,000
Deferred tax assets	1,024,000,000		1,024,000,000	1,400,000,000
Mississippi Power [Member] | Kemper IGCC [Member]
Income Tax Disclosure [Line Items]
Unrecognized tax benefits	464,000,000		464,000,000
Interest accrued during the period			28,000,000
Alabama Power [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes			(108,000,000)	121,000,000	436,000,000
Tax regulatory assets	526,000,000		526,000,000
Tax regulatory liabilities	65,000,000		65,000,000
Amortization of deferred investment tax credits			8,000,000	8,000,000	8,000,000
Deferred tax assets	1,544,000,000		1,544,000,000	1,511,000,000
Georgia Power [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes			170,000,000	506,000,000	507,000,000
Tax regulatory assets	681,000,000		681,000,000
Tax regulatory liabilities	121,000,000		121,000,000
Amortization of deferred investment tax credits			10,000,000	10,000,000	10,000,000
State investment tax credit			42,000,000	33,000,000	34,000,000
Federal tax credits			83,000,000
State investment tax credit carryforward			201,000,000
Deferred tax assets	2,382,000,000		2,382,000,000	2,077,000,000
Gulf Power [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes			21,000,000	(7,000,000)	44,000,000
Tax regulatory assets	58,000,000		58,000,000
Tax regulatory liabilities	2,000,000		$ 2,000,000
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern			12 months
Deferred tax assets	244,000,000		$ 244,000,000	216,000,000
Southern Power [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes			116,000,000	(518,000,000)	(220,000,000)
Amortization of deferred investment tax credits			$ 37,000,000	19,000,000	11,000,000
Reduction in tax basis of assets			50.00%
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern			12 months
Unrecognized tax benefits	17,000,000		$ 17,000,000	8,000,000	5,000,000	$ 2,000,000
Net operating loss carryforward	1,030,000,000		1,030,000,000
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward	40,000,000		40,000,000	8,000,000
Deferred tax assets	2,937,000,000		2,937,000,000	794,000,000
Southern Power [Member] | Production Tax Credit Carryforward [Member]
Income Tax Disclosure [Line Items]
Effective Income Tax Rate Reconciliation, Tax Credit, Production, Amount			42,000,000	1,000,000
Southern Power [Member] | Investment Tax Credit Carryforward [Member]
Income Tax Disclosure [Line Items]
Deferred tax assets	292,000,000		292,000,000	149,000,000
Southern Power [Member] | Investment Tax Credit Carryforward [Member] | Nacogdoches Biomass Generating Plant [Member]
Income Tax Disclosure [Line Items]
Tax credit carryforward				162,000,000	74,000,000
Reduction in income tax expense, investment tax credits			173,000,000	54,000,000	48,000,000
Florida
Income Tax Disclosure [Line Items]
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward	7,000,000		7,000,000
Florida | Southern Power [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforward	185,000,000		185,000,000
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward	7,000,000		7,000,000
General Business Tax Credit Carryforward [Member] | Southern Power [Member]
Income Tax Disclosure [Line Items]
Tax credit carryforward	1,700,000,000		1,700,000,000
Investment Tax Credit Carryforward [Member]
Income Tax Disclosure [Line Items]
Tax positions not impacting the effective tax rate	92,000,000		92,000,000
Investment Tax Credit Carryforward [Member] | Southern Power [Member]
Income Tax Disclosure [Line Items]
Tax positions not impacting the effective tax rate	92,000,000		92,000,000
Federal [Member] | Southern Power [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforward	2,800,000,000		2,800,000,000
State [Member] | Southern Power [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforward	1,000,000,000		1,000,000,000	225,000,000
Tax Year 2016 [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforward	2,800,000,000		2,800,000,000
Successor [Member] | Southern Company Gas [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes	23,000,000
Tax regulatory liabilities	22,000,000		22,000,000
Amortization of deferred investment tax credits	1,000,000
Unrecognized tax benefits	0		0
Deferred tax assets	598,000,000		598,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 0		$ 0
Predecessor [Member] | Southern Company Gas [Member]
Income Tax Disclosure [Line Items]
Net cash payments/(refunds) for income taxes		$ (100,000,000)		(26,000,000)	422,000,000
Amortization of deferred investment tax credits		1,000,000		2,000,000	2,000,000
Unrecognized tax benefits		$ 0		0	$ 0
Deferred tax assets				$ 438,000,000

Income Taxes - NOL Carryforward

Income Taxes - NOL Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	$ 3,000
Net State Income Tax Benefit	203
Mississippi
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	112
Oklahoma
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	31
Georgia
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	25
New York
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	11
New York City
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	12
Florida
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	7
Other states
Operating Loss Carryforwards [Line Items]
Net State Income Tax Benefit	5
Southern Power [Member]
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	1,030
Net State Income Tax Benefit	40	$ 8
Southern Power [Member] | Oklahoma
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	838
Net State Income Tax Benefit	32
Southern Power [Member] | Florida
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	185
Net State Income Tax Benefit	7
Southern Power [Member] | Other states
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	7
Net State Income Tax Benefit	1
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	5,754
State and Local Jurisdiction [Member] | Mississippi
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	3,448
State and Local Jurisdiction [Member] | Oklahoma
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	839
State and Local Jurisdiction [Member] | Georgia
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	685
State and Local Jurisdiction [Member] | New York
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	229
State and Local Jurisdiction [Member] | New York City
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	209
State and Local Jurisdiction [Member] | Florida
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	198
State and Local Jurisdiction [Member] | Other states
Operating Loss Carryforwards [Line Items]
NOL Carryforwards	$ 146

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, 2016USD ($)$ / sharesshares	Jan. 31, 2016USD ($)	Dec. 31, 2015USD ($)shares
Debt Disclosure [Line Items]
2,018		$ 2,353		$ 1,697
2,019		3,076		1,176
2,020		1,326		1,327
Scheduled maturities and redemptions of securities due within one year
Senior notes		1,995		1,810
Other long-term debt		485		829
Pollution control revenue bonds		76		4
Capitalized leases		32		32
Unamortized debt issuance expense		(1)		(1)
Total		2,587		2,674
Total		2,019		1,995
Georgia Power [Member]
Debt Disclosure [Line Items]
2,018		748		747
2,019		500		502
2,020		325		0
Scheduled maturities and redemptions of securities due within one year
Senior notes		450		700
Pollution control revenue bonds		0		4
Capitalized leases		10		8
Total		460		712
Total		450		450
Southern Power [Member]
Debt Disclosure [Line Items]
2,018		670
2,019		600
2,020		300
Scheduled maturities and redemptions of securities due within one year
Total		560		403
Total		561
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Five		300
Alabama Power [Member]
Debt Disclosure [Line Items]
2,019		200		200
2,020		250		250
Scheduled maturities and redemptions of securities due within one year
Total		561		200
Total		$ 525		525
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 | $ / shares		$ 100
Temporary Equity, Shares Outstanding | shares		80,000
Redemption Price Per Share | $ / shares		$ 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 | $ / shares		$ 100
Temporary Equity, Shares Outstanding | shares		50,000
Redemption Price Per Share | $ / shares		$ 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 | $ / shares		$ 100
Temporary Equity, Shares Outstanding | shares		60,000
Redemption Price Per Share | $ / shares		$ 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 | $ / shares		$ 100
Temporary Equity, Shares Outstanding | shares		100,000
Redemption Price Per Share | $ / shares		$ 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 | $ / shares		$ 100
Temporary Equity, Shares Outstanding | shares		50,000
Redemption Price Per Share | $ / shares		$ 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 | $ / shares		$ 100
Temporary Equity, Shares Outstanding | shares		135,115
Redemption Price Per Share | $ / shares		$ 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 | $ / shares		$ 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 | $ / shares		$ 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 | $ / shares		$ 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 | $ / shares	$ 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
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]
Debt Disclosure [Line Items]
Long-term debt affiliated		$ 551		0
2,019		$ 125		$ 125
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		$ 35		$ 300
Other long-term debt		63
Pollution control revenue bonds		40		0
Capitalized leases		3		3
Bank term loans		0		425
Total		629		728
Total		$ 35		$ 35
Mississippi Power [Member] | 4.40% Redeemable Preferred Stock [Member]
Redeemable Preferred/Preference Stock [Abstract]
Par Value/Stated Capital Per Share | $ / shares		$ 100,000,000
Temporary Equity, Shares Outstanding | shares		8,867,000,000
Redemption Price Per Share | $ / shares		$ 104.32
Mississippi Power [Member] | 4.72% Redeemable Preferred Stock [Member]
Redeemable Preferred/Preference Stock [Abstract]
Par Value/Stated Capital Per Share | $ / shares		$ 100,000,000
Temporary Equity, Shares Outstanding | shares		16,700,000,000
Redemption Price Per Share | $ / shares		$ 102.25
Mississippi Power [Member] | 4.60% Redeemable Preferred Stock [Member]
Redeemable Preferred/Preference Stock [Abstract]
Par Value/Stated Capital Per Share | $ / shares		$ 100,000,000
Temporary Equity, Shares Outstanding | shares		8,643,000,000
Redemption Price Per Share | $ / shares		$ 107
Mississippi Power [Member] | 5.25% Redeemable Preferred Stock [Member]
Redeemable Preferred/Preference Stock [Abstract]
Par Value/Stated Capital Per Share | $ / shares		$ 100,000,000
Temporary Equity, Shares Outstanding | shares		300,000,000,000
Redemption Price Per Share | $ / shares		$ 100
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 ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2015
Credit arrangements by company
Expires, 2017	$ 423
Expires, 2018	3,620
Expires, 2020	4,400
Total	8,443
Unused	8,273
Executable Term-Loans, One Year	65
Executable Term-Loans, Two Years	13
Due Within One Year, Term Out	58
Due Within One Year, No Term Out	365
Southern Company Gas Capital [Member]
Credit arrangements by company
Expires, 2017	49
Expires, 2018	1,251
Total	1,300
Unused	1,249
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	49
Southern Company [Member]
Credit arrangements by company
Expires, 2017	0
Expires, 2018	1,000
Expires, 2020	1,250
Total	2,250
Unused	2,250
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, 2017	35
Expires, 2018	500
Expires, 2020	800
Total	1,335
Unused	1,335
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	35
Georgia Power [Member]
Credit arrangements by company
Expires, 2017	0
Expires, 2018	0
Expires, 2020	1,750
Total	1,750
Unused	1,732
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, 2017	85
Expires, 2018	195
Expires, 2020	0
Total	280
Unused	280
Executable Term-Loans, One Year	45
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	25
Due Within One Year, No Term Out	60
Gulf Power [Member]
Credit arrangements by company
Expires, 2017	75
Expires, 2018	1,925
Expires, 2020	0
Total	2,000
Unused	1,949
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	75
Nicor Gas [Member]
Credit arrangements by company
Expires, 2017	26
Expires, 2018	674
Total	700
Unused	700
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	26
Mississippi Power [Member]
Credit arrangements by company
Expires, 2017	173
Expires, 2018	0
Expires, 2020	0
Total	173
Unused	150
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	13
Due Within One Year, Term Out	13
Due Within One Year, No Term Out	160
Southern Power [Member]
Credit arrangements by company
Expires, 2017	0
Expires, 2018	0
Expires, 2020	600
Total	600		$ 600
Unused	522	$ 566
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, 2017	55
Expires, 2018	0
Expires, 2020	0
Total	55
Unused	55
Executable Term-Loans, One Year	20
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	20
Due Within One Year, No Term Out	35
Continuing Letter of Credit Facility [Member] | Southern Power [Member]
Credit arrangements by company
Total	120
Unused	$ 82

Financing - Short-term Borrowin

Financing - Short-term Borrowings (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 2,032,000,000	$ 1,240,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.10%	0.90%
Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 1,909,000,000	$ 740,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.10%	0.70%
Short-term bank debt [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 123,000,000	$ 500,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.70%	1.40%
Georgia Power [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 392,000,000	$ 158,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.10%	0.60%
Gulf Power [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 268,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.20%
Gulf Power [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 168,000,000	$ 142,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.10%	0.70%
Gulf Power [Member] | Short-term bank debt [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 100,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.50%
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] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	0	0
Successor [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 1,257,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.03%
Successor [Member] | Southern Company Gas Capital [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 733,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	1.09%
Successor [Member] | Nicor Gas [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding	$ 524,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.95%
Predecessor [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding		$ 1,010,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate		0.60%
Predecessor [Member] | Southern Company Gas Capital [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding		$ 471,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate		0.71%
Predecessor [Member] | Nicor Gas [Member] | Commercial paper [Member]
Short-term borrowings
Short-term Debt at the End of the Period, Amount Outstanding		$ 539,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate		0.52%

Financing - Schedule of Borrowi

Financing - Schedule of Borrowings Under FFB Credit Facility (Details) - Georgia Power [Member] - USD ($) $ in Millions	Dec. 31, 2016	Jun. 30, 2016
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 125	$ 300
Line of Credit [Member] | Debt Due Two Thousand Forty Four [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.142%	2.571%

Financing - Schedule Of Credit

Financing - Schedule Of Credit Arrangements With Project Credit Facilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2015
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 8,443
Line of Credit Facility, Remaining Borrowing Capacity	8,273
Southern Power [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	600		$ 600
Line of Credit Facility, Remaining Borrowing Capacity	522	$ 566
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	34
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	$ 16

Financing - Outstanding Classes

Financing - Outstanding Classes of Capital Stock (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Temporary Equity [Line Items]
Redeemable preferred stock	$ 118	$ 118	$ 375
Preferred and preference stock	$ 0	$ 412	$ 0
Mississippi Power [Member]
Temporary Equity [Line Items]
Temporary Equity, Shares Outstanding	334,210	334,210
Preferred Stock Dividend Rate Stated Percentage Rate Range Maximum	5.25%	5.25%
Redeemable Preferred Stock [Member]
Temporary Equity [Line Items]
Redeemable preferred stock	$ 118	$ 118		$ 375
Preferred and preference stock		262
Temporary Equity, Other Changes		$ 5
Depositary Shares [Member] | Mississippi Power [Member]
Temporary Equity [Line Items]
Temporary Equity, Shares Outstanding	1,200,000,000,000

Financing - Textual (Details)

Financing - Textual (Details)	Feb. 21, 2017USD ($)shares	Dec. 14, 2016USD ($)	Oct. 26, 2016	Jun. 27, 2016USD ($)	Mar. 08, 2016USD ($)	Jan. 28, 2016USD ($)	Jul. 15, 2015USD ($)	Jun. 03, 2015USD ($)	Feb. 20, 2014USD ($)	Sep. 30, 2016USD ($)	May 31, 2016USD ($)	Feb. 29, 2016USD ($)	May 31, 2015USD ($)$ / sharesshares	Jan. 31, 2015USD ($)	Sep. 30, 2013	Dec. 31, 2016USD ($)leased_asset_unitsseriesshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2016EUR (€)leased_asset_unitsseriesshares	Oct. 07, 2016USD ($)	Sep. 01, 2016	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Jan. 31, 2016USD ($)	Jan. 19, 2016USD ($)	Aug. 31, 2015USD ($)	Jan. 01, 2015shares	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																$ 2,587,000,000	$ 2,674,000,000
2,021																2,655,000,000	200,000,000
Redeemable preferred stock																118,000,000	118,000,000	$ 375,000,000
Financing (Textual) [Abstract]
Proceeds from issuance of junior subordinated notes																206,000,000	206,000,000
Other Long-term Debt																9,404,000,000	6,808,000,000
Senior notes, current																1,995,000,000	1,810,000,000
Other Long-term Debt																485,000,000	829,000,000
Long term debt and capital lease obligations, maturities in 2014																2,600,000,000
Long term debt and capital lease obligations, maturities in 2015																3,900,000,000
Long term debt and capital lease obligations, maturities in 2016																3,200,000,000
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four																1,400,000,000
Long term debt and capital lease obligations, maturities in 2018																3,100,000,000
2,017																2,019,000,000	1,995,000,000
2,018																2,353,000,000	1,697,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five																21,797,000,000	10,972,000,000
2,019																$ 3,076,000,000	1,176,000,000
Ratio of indebtedness to capitalization, debt covenant, required																70.00%				70.00%							65.00%
Senior Notes outstanding																$ 33,000,000,000	19,100,000,000
Capitalized lease obligations																136,000,000	146,000,000
Accumulated depreciation PPE																29,852,000,000	24,253,000,000
Unused credit with banks																8,273,000,000
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support																1,900,000,000
Short Term Borrowings Excluding Other Energy Service Contracts																2,032,000,000	1,240,000,000
Remarketed pollution control bonds																400,000,000
Long-term Pollution Control Bond, Current																76,000,000	$ 4,000,000
Expires, 2020																$ 4,400,000,000
Common Stock, Shares, Issued | shares																991,000,000	915,000,000			991,000,000
Common stock issuances																$ 3,758,000,000	$ 256,000,000	806,000,000
Short-term debt																$ 2,241,000,000	1,376,000,000
Commitment fee percentage (less than 1/4 of 1%)																0.25%
Line of Credit Facility, Maximum Borrowing Capacity																$ 8,443,000,000
2,020																1,326,000,000	1,327,000,000
Line of Credit Expire Year One																423,000,000
Assets																109,697,000,000	78,318,000,000	70,233,000,000
Building [Member]
Financing (Textual) [Abstract]
Capital leased assets, gross																61,000,000	61,000,000
Maturity of Junior Subordinated Notes Due Two Thousand Seventy Five [Member]
Financing (Textual) [Abstract]
Junior subordinated notes																2,350,000,000	1,000,000,000
Trust Preferred Securities Subject to Mandatory Redemption [Member]
Financing (Textual) [Abstract]
Preferred securities, outstanding																200,000,000	200,000,000
Senior Notes [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																8,500,000,000
Georgia Power [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																460,000,000	712,000,000
Financing (Textual) [Abstract]
Line of Credit Facility, Current Borrowing Capacity																125,000,000							$ 300,000,000
Other Long-term Debt																4,445,000,000	4,024,000,000
Senior notes, current																450,000,000	700,000,000
Long term debt and capital lease obligations, maturities in 2014																460,000,000
Long term debt and capital lease obligations, maturities in 2015																762,000,000
Long term debt and capital lease obligations, maturities in 2016																513,000,000
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four																57,000,000
Long term debt and capital lease obligations, maturities in 2018																376,000,000
2,017																450,000,000	450,000,000
2,018																748,000,000	747,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five																4,175,000,000	3,850,000,000
2,019																$ 500,000,000	502,000,000
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																$ 6,200,000,000	6,300,000,000
Amortization Period For Line Of Credit Facility									5 years
Pollution control revenue bonds, outstanding																1,800,000,000	1,800,000,000
Repayments of Senior Debt																700,000,000	1,175,000,000	0
Capitalized lease obligations																169,000,000	183,000,000
Accumulated depreciation PPE																11,317,000,000	10,903,000,000
Unused credit with banks																1,732,000,000
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support																868,000,000
Pollution Control Revenue Bonds Required To Be Remarketed																250,000,000
Long-term Pollution Control Bond, Current																$ 0	4,000,000
Redemption price of redeemable preferred stock, as a percent of liquidation amount																100.00%				100.00%
Expires, 2020																$ 1,750,000,000
Short-term debt																$ 391,000,000	158,000,000
Commitment fee percentage (less than 1/4 of 1%)																0.25%
Line of Credit Facility, Maximum Borrowing Capacity																$ 1,750,000,000
2,020																325,000,000	0
Capital contributions from parent company																594,000,000	62,000,000	549,000,000
Line of Credit Expire Year One																0
Assets																34,835,000,000	32,865,000,000
Georgia Power [Member] | Corporate, Non-Segment [Member]
Financing (Textual) [Abstract]
Capital leased assets, gross																61,000,000
Capitalized lease obligations																	61,000,000
Accumulated depreciation PPE																33,000,000	26,000,000
Georgia Power [Member] | Building [Member]
Financing (Textual) [Abstract]
Capitalized lease obligations																$ 28,000,000	$ 35,000,000
Georgia Power [Member] | Line of Credit [Member] | Debt Due Two Thousand Forty Four [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																3.142%				3.142%			2.571%
Georgia Power [Member] | Capital Lease Obligations
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																$ 2,800,000,000	$ 2,400,000,000
Georgia Power [Member] | Secured Debt [Member] | FFB Loan [Member]
Financing (Textual) [Abstract]
Long-term Debt																$ 2,600,000,000	2,200,000,000
Georgia Power [Member] | Senior Notes [Member] | Series 2016B [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																								$ 325,000,000
Fixed stated interest rate of debt obligation																								2.40%
Georgia Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																								$ 325,000,000
Fixed stated interest rate of debt obligation																								3.25%
Georgia Power [Member] | Unsecured Debt [Member] | Series 2013B [Member]
Financing (Textual) [Abstract]
Redemption Amount of Principal Notes																								$ 250,000,000
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member]
Financing (Textual) [Abstract]
Percent ownership									45.70%
Georgia Power [Member] | Vogtle Units Three and Four [Member]
Financing (Textual) [Abstract]
Percent ownership																45.70%				45.70%
Mississippi Power [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																$ 629,000,000	$ 728,000,000
Working Capital																$ 371,000,000
Temporary Equity, Shares Outstanding | shares																334,210	334,210			334,210
Financing (Textual) [Abstract]
Promissory Note						$ 275,000,000		$ 301,000,000								$ 0	$ 301,000,000	0
Line of Credit Facility, Current Borrowing Capacity																100,000,000										$ 100,000,000
Other Long-term Debt																904,000,000	929,000,000
Senior notes, current																35,000,000	300,000,000
Other Long-term Debt																63,000,000
Long term debt and capital lease obligations, maturities in 2014																629,000,000
Long term debt and capital lease obligations, maturities in 2015																1,200,000,000
Long term debt and capital lease obligations, maturities in 2016																128,000,000
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four																10,000,000
Long term debt and capital lease obligations, maturities in 2018																274,000,000
2,017																35,000,000	35,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five																680,000,000	680,000,000
2,019																125,000,000	125,000,000
Bank Loans																1,200,000,000	900,000,000
Bank loans outstanding																1,200,000,000	900,000,000
Bank term loans																$ 0	425,000,000
Ratio of indebtedness to capitalization, debt covenant, required																65.00%				65.00%
Senior Notes outstanding																$ 790,000,000	1,100,000,000
Pollution control revenue bonds, outstanding																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																300,000,000	0	0
Other revenue bond obligation																50,000,000	50,000,000
Period Of Nitrogen Supply Agreement															20 years
Capitalized lease obligations																74,000,000	77,000,000
Capital leases, due 2017																7,000,000
Capital leases, due 2018																7,000,000
Capital leases, due 2019																7,000,000
Capital leases, due 2020																7,000,000
Capital leases, due 2021																7,000,000
Capital leases, due 2022 and thereafter																7,000,000
Accumulated depreciation PPE																1,289,000,000	1,262,000,000
Unused credit with banks																150,000,000
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support																40,000,000
Long-term Pollution Control Bond, Current																$ 40,000,000	0
Redemption price of redeemable preferred stock, as a percent of liquidation amount																100.00%				100.00%
Expires, 2020																$ 0
Short-term debt																$ 23,000,000	500,000,000
Commitment fee percentage (less than 1/4 of 1%)																0.25%
Line of Credit Facility, Maximum Borrowing Capacity																$ 173,000,000
Capital contributions from parent company		$ 400,000,000		$ 225,000,000												627,000,000	277,000,000	451,000,000
Line of Credit Expire Year One																173,000,000
Assets																8,235,000,000	7,840,000,000
Mississippi Power [Member] | Kemper IGCC [Member]
Financing (Textual) [Abstract]
Capitalized lease obligations																$ 74,000,000	$ 77,000,000
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] | Series 1999A [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																		7.13%
Mississippi Power [Member] | Notes Payable to Banks [Member]
Financing (Textual) [Abstract]
Repayments of Senior Debt					$ 900,000,000
Mississippi Power [Member] | Capital Lease Obligations
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																4.90%	4.90%			4.90%
Mississippi Power [Member] | Senior Notes [Member]
Financing (Textual) [Abstract]
Redemption Amount of Principal Notes					300,000,000
Fixed stated interest rate of debt obligation																							2.35%
Mississippi Power [Member] | Unsecured Debt [Member]
Financing (Textual) [Abstract]
Line of Credit Facility, Current Borrowing Capacity					900,000,000																$ 300,000,000
Line of Credit Facility, Maximum Borrowing Capacity					$ 1,200,000,000
Southern Company Gas [Member]
Debt Instrument [Line Items]
2,021																$ 330,000,000
Financing (Textual) [Abstract]
2,017																22,000,000
2,018																155,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five																3,900,000,000
2,019																$ 350,000,000
Ratio of indebtedness to capitalization, debt covenant, required																70.00%				70.00%
Senior Notes outstanding																$ 3,700,000,000	$ 2,500,000,000
Unused credit with banks																1,949,000,000
Expires, 2020																0
Line of Credit Facility, Maximum Borrowing Capacity																2,000,000,000
2,020																$ 0
Restrictions On Payment Of Dividends To Parent																70.00%
Retained Earnings, Unappropriated																$ 688,000,000
First Mortgage Bonds																625,000,000	375,000,000
Gas Facility Revenue Bonds																200,000,000	200,000,000
Line of Credit Expire Year One																75,000,000
Southern Company Gas [Member] | Medium-term Notes [Member]
Financing (Textual) [Abstract]
2,017																22,000,000
Southern Company Gas [Member] | Senior Notes Due 2026 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation										3.95%	3.25%
Southern Company Gas [Member] | Senior Notes Due 2016 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation											6.375%
Southern Company Gas [Member] | Senior Notes Due 2023 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation											2.45%
Southern Company Gas [Member] | First Mortgage Bonds And Senior Notes [Member]
Financing (Textual) [Abstract]
2,017																$ 545,000,000
Southern Company Gas [Member] | Senior Notes Due October 2018 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																3.50%				3.50%
Southern Company Gas [Member] | Promissory Note [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										$ 360,000,000
Southern Company Gas [Member] | Callable Debt [Member]
Financing (Textual) [Abstract]
Long-term Debt, Current Maturities																$ 120,000,000							$ 275,000,000
Long-term Debt																$ 155,000,000
Southern Company Gas [Member] | Gas Facility Revenue Bonds [Member]
Financing (Textual) [Abstract]
Debt Instrument, Number of Series Issued | series																5
Southern Company Gas [Member] | Senior Notes [Member] | Senior Notes Due 2026 [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										550,000,000	$ 350,000,000
Southern Company Gas [Member] | Senior Notes [Member] | Senior Notes Due 2016 [Member]
Financing (Textual) [Abstract]
Repayments of Senior Debt										120,000,000	300,000,000
Southern Company Gas [Member] | Senior Notes [Member] | Senior Notes Due 2023 [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										350,000,000
Southern Company Gas [Member] | Medium-term Notes [Member]
Financing (Textual) [Abstract]
Long-term Debt																$ 159,000,000	181,000,000
Gulf Power [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																87,000,000	110,000,000
2,021																0
Financing (Textual) [Abstract]
Other Long-term Debt																309,000,000	309,000,000
2,017																87,000,000	85,000,000
2,018																0
Long-term Debt, Maturities, Repayments of Principal after Year Five																515,000,000	640,000,000
2,019																0
Bank Loans																$ 100,000,000
Ratio of indebtedness to capitalization, debt covenant, required																65.00%				65.00%
Line of Credit Facility, Amount Available to Support Variable Rate Pollution Control Revenue Bonds																$ 82,000,000
Senior Notes outstanding																777,000,000	1,010,000,000
Secured Debt																41,000,000	41,000,000
Pollution control revenue bonds, outstanding																309,000,000	309,000,000
Repayments of Senior Debt																235,000,000	60,000,000	$ 75,000,000
Accumulated depreciation PPE																1,382,000,000	1,296,000,000
Unused credit with banks																280,000,000
Short Term Borrowings Excluding Other Energy Service Contracts																268,000,000
Pollution Control Revenue Bonds Required To Be Remarketed																$ 86,000,000
Redemption price of redeemable preferred stock, as a percent of liquidation amount																100.00%				100.00%
Expires, 2020																$ 0
Common Stock, Shares, Issued | shares																												200,000
Common stock issuances														$ 20,000,000		$ 0	20,000,000	50,000,000
Number of Issuance Pollution Control Revenue Bonds | series																2				2
Short-term debt																$ 268,000,000	142,000,000
Commitment fee percentage (less than 1/4 of 1%)																0.25%
Line of Credit Facility, Maximum Borrowing Capacity																$ 280,000,000
2,020																175,000,000	175,000,000
Capital contributions from parent company																20,000,000	4,000,000	4,000,000
Line of Credit Expire Year One																85,000,000
Assets																$ 4,822,000,000	4,920,000,000
Gulf Power [Member] | Subsequent Event [Member]
Financing (Textual) [Abstract]
Common Stock, Shares, Issued | shares	1,750,000
Common stock issuances	$ 175,000,000
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
Gulf Power [Member] | Series 2011A [Member]
Financing (Textual) [Abstract]
Redemption Amount of Principal Notes											$ 125,000,000
Gulf Power [Member] | Long-term Debt, Current [Member]
Financing (Textual) [Abstract]
2,017																	110,000,000
Gulf Power [Member] | Bank Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Term											11 months
Financing (Textual) [Abstract]
Debt Instrument, Face Amount											$ 100,000,000
Gulf Power [Member] | Senior Notes [Member] | Series 2011A [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation											5.75%
Alabama Power [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																561,000,000	200,000,000
2,021																$ 220,000,000	200,000,000
Ownership percentage, equity method investment																50.00%				50.00%
Redeemable preferred stock																$ 85,000,000	85,000,000
Senior Notes And Pollution Control Revenue Bonds, Current																561,000,000	200,000,000
Financing (Textual) [Abstract]
Proceeds from issuance of junior subordinated notes																206,000,000	206,000,000
Other Long-term Debt																1,096,000,000	1,097,000,000
2,017																525,000,000	525,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five																4,625,000,000	4,225,000,000
2,019																200,000,000	200,000,000
Bank Loans																$ 45,000,000
Ratio of indebtedness to capitalization, debt covenant, required																65.00%				65.00%
Percent ownership																14.00%				14.00%
Pollution control revenue bonds, outstanding																$ 1,100,000,000	1,100,000,000
Repayments of Senior Debt																200,000,000	650,000,000	0
Capitalized lease obligations																4,000,000	5,000,000
Accumulated depreciation PPE																9,112,000,000	8,736,000,000
Unused credit with banks																1,335,000,000
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support																890,000,000
Pollution Control Revenue Bonds Required To Be Remarketed																87,000,000
Short-term debt outstanding, regulatory approved maximum																2,100,000,000
Expires, 2020																800,000,000
Short-term debt																$ 0	0
Commitment fee percentage (less than 1/4 of 1%)																0.10%
Line of Credit Facility, Maximum Borrowing Capacity																$ 1,335,000,000
Temporary Equity, Other Changes													$ 5,000,000
2,020																250,000,000	250,000,000
Capital contributions from parent company																260,000,000	22,000,000	28,000,000
Line of Credit Expire Year One																35,000,000
Assets																22,516,000,000	21,721,000,000
Alabama Power [Member] | Trust Preferred Securities Subject to Mandatory Redemption [Member]
Financing (Textual) [Abstract]
Preferred securities, outstanding																200,000,000	$ 200,000,000
Alabama Power [Member] | Series FF [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																									5.20%
Alabama Power [Member] | Senior Notes And Pollution Control Bond [Member]
Debt Instrument [Line Items]
2,021																310,000,000
Financing (Textual) [Abstract]
2,017																561,000,000
2,018																200,000,000
2,019																0
2,020																$ 250,000,000
Alabama Power [Member] | Bank Loans [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																								$ 45,000,000
Fixed stated interest rate of debt obligation																								2.38%
Alabama Power [Member] | Capital Lease Obligations
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																6.90%	6.90%			6.90%
Alabama Power [Member] | Senior Notes [Member] | Series Z [Member] | Subsequent Event [Member]
Financing (Textual) [Abstract]
Redemption Amount of Principal Notes	$ 200,000,000
Fixed stated interest rate of debt obligation	5.55%
Alabama Power [Member] | Senior Notes [Member] | Series 2016A [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																									$ 200,000,000
Senior Notes outstanding																$ 5,800,000,000	$ 5,600,000,000
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																$ 29,000,000	30,000,000
Subsidiaries [Member] | Capital Lease Obligations | Minimum [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																1.40%				1.40%
Subsidiaries [Member] | Capital Lease Obligations | Maximum [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																3.40%				3.40%
Southern Power and Traditional Operating Companies [Member] | Senior Notes [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																$ 4,800,000,000
Southern Power [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																560,000,000	403,000,000
Financing (Textual) [Abstract]
Prepayment of debt																6,000,000
Line of Credit Facility, Current Borrowing Capacity																78,000,000	34,000,000
Other Long-term Debt																15,000,000	13,000,000
2,017																561,000,000
2,018																670,000,000
2,019																600,000,000
Bank Loans																$ 380,000,000	400,000,000
Ratio of indebtedness to capitalization, debt covenant, required																65.00%				65.00%
Senior Notes outstanding																$ 5,300,000,000	2,700,000,000
Repayments of Senior Debt																200,000,000	525,000,000	0
Accumulated depreciation PPE																1,484,000,000	1,248,000,000
Unused credit with banks																522,000,000	566,000,000
Expires, 2020																600,000,000
Short-term debt																$ 209,000,000	137,000,000
Commitment fee percentage (less than 1/4 of 1%)																0.25%
Line of Credit Facility, Maximum Borrowing Capacity																$ 600,000,000											$ 600,000,000
2,020																300,000,000
Capital contributions from parent company																1,850,000,000	$ 646,000,000	$ 146,000,000
Line of Credit Expire Year One																0
Life Output Of Plant																	20 years
Assets																15,169,000,000	$ 8,905,000,000
Southern Power [Member] | Bank Loans, Current [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																60,000,000	400,000,000
Southern Power [Member] | Senior Notes, Current [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Current																500,000,000
Southern Power [Member] | Notes Payable to TRE [Member]
Financing (Textual) [Abstract]
Other Long-term Debt																$ 1,000,000	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] | Bank Loans [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										60,000,000
Repayments of Senior Debt										80,000,000
Southern Power [Member] | Bank Loans [Member] | Debt Due Two Thousand Sixteen [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										400,000,000
Southern Power [Member] | Bank Loans [Member] | Debt Due Two Thousand Eighteen [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										$ 320,000,000
Southern Power [Member] | Senior Notes [Member] | Series 2015A [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount													$ 600,000,000
Fixed stated interest rate of debt obligation													1.00%
Southern Power [Member] | Senior Notes [Member] | Series 2015B [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount													$ 500,000,000
Fixed stated interest rate of debt obligation													1.85%
Southern Power [Member] | Senior Notes [Member] | Series Two Thousand Three [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation							2.75%
Repayments of Senior Debt							$ 290,000,000
Southern Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount | €																				€ 600,000,000
Fixed stated interest rate of debt obligation																1.95%				1.95%
Southern Power [Member] | Senior Notes [Member] | Series 2016E [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount | €																				€ 300,000,000
Fixed stated interest rate of debt obligation																2.50%				2.50%
Southern Power [Member] | Senior Notes [Member] | Series 2016F [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount | €																				€ 400,000,000
Fixed stated interest rate of debt obligation																4.95%				4.95%
Southern Power [Member] | Senior Notes [Member] | Series E [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount | €																				€ 200,000,000
Fixed stated interest rate of debt obligation																6.375%				6.375%
Southern Company And Subsidiaries [Member] | Senior Notes [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																$ 13,300,000,000
Traditional Operating Companies
Financing (Textual) [Abstract]
Pollution control revenue bonds, outstanding																3,300,000,000	3,300,000,000
Southern Company Gas Capital [Member]
Financing (Textual) [Abstract]
Unused credit with banks																1,249,000,000
Line of Credit Facility, Maximum Borrowing Capacity																1,300,000,000
Line of Credit Expire Year One																49,000,000
Nicor Gas [Member]
Financing (Textual) [Abstract]
Unused credit with banks																700,000,000
Line of Credit Facility, Maximum Borrowing Capacity																700,000,000
Line of Credit Expire Year One																26,000,000
Nicor Gas [Member] | Senior Notes And Pollution Control Bond [Member]
Debt Instrument [Line Items]
Repayments of First Mortgage Bond											$ 50,000,000	$ 75,000,000
Nicor Gas [Member] | First Mortgage Bonds Due 2026 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation										2.66%
Nicor Gas [Member] | First Mortgage Bonds Due 2031 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation										2.91%
Nicor Gas [Member] | First Mortgage Bonds Due 2036 [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																							3.27%
Nicor Gas [Member] | Senior Notes And Pollution Control Bond [Member] | Senior Notes Due Two Thousand Seventy Six [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																							$ 250,000,000
Nicor Gas [Member] | Senior Notes And Pollution Control Bond [Member] | First Mortgage Bonds Due 2026 [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																							100,000,000
Nicor Gas [Member] | Senior Notes And Pollution Control Bond [Member] | First Mortgage Bonds Due 2031 [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																							100,000,000
Nicor Gas [Member] | Senior Notes And Pollution Control Bond [Member] | First Mortgage Bonds Due 2036 [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																							$ 50,000,000
Parent Company [Member]
Financing (Textual) [Abstract]
Bank Loans																$ 400,000,000	400,000,000
Ratio of indebtedness to capitalization, debt covenant, required																70.00%				70.00%
Senior Notes outstanding																$ 10,300,000,000	2,400,000,000
Unused credit with banks																2,250,000,000
Expires, 2020																1,250,000,000
Line of Credit Facility, Maximum Borrowing Capacity																2,250,000,000
Line of Credit Expire Year One																0
Parent Company [Member] | Series 2011A [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation										1.95%
Parent Company [Member] | Unsecured Debt [Member] | Series 2011A [Member]
Financing (Textual) [Abstract]
Repayments of Senior Debt										$ 500,000,000
Parent Company [Member] | Junior Subordinated Debt [Member] | Senior Notes Due Two Thousand Seventy Six [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount										$ 800,000,000
Fixed stated interest rate of debt obligation										5.25%
Parent Company [Member] | Junior Subordinated Debt [Member] | Junior Subordinated Notes Due Two Thousand Fifty Seven [Member]
Financing (Textual) [Abstract]
Debt Instrument, Face Amount																$ 550,000,000
Fixed stated interest rate of debt obligation																5.50%				5.50%
Southern Natural Gas Company, LLC [Member] | Southern Company Gas [Member]
Debt Instrument [Line Items]
Ownership percentage, equity method investment																						50.00%
Notes due September 30, 2032 [Member] | Southern Power [Member]
Financing (Textual) [Abstract]
Promissory Note																$ 5,000,000
Capital Lease Obligations | Georgia Power [Member] | Secured Debt [Member]
Financing (Textual) [Abstract]
Long-term Debt																$ 169,000,000	183,000,000
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
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																$ 1,909,000,000	740,000,000
Commercial Paper [Member] | Georgia Power [Member]
Financing (Textual) [Abstract]
Short Term Borrowings Excluding Other Energy Service Contracts																392,000,000	158,000,000
Commercial Paper [Member] | Mississippi Power [Member]
Financing (Textual) [Abstract]
Short Term Borrowings Excluding Other Energy Service Contracts																0	0
Commercial Paper [Member] | Gulf Power [Member]
Financing (Textual) [Abstract]
Short Term Borrowings Excluding Other Energy Service Contracts																168,000,000	142,000,000
Commercial Paper [Member] | Southern Power [Member]
Financing (Textual) [Abstract]
Short Term Borrowings Excluding Other Energy Service Contracts																0	0
Long-term Debt [Member] | Parent Company [Member]
Financing (Textual) [Abstract]
Bank Loans																2,000,000,000
Short-term Debt [Member] | Mississippi Power [Member]
Financing (Textual) [Abstract]
Bank loans outstanding																	475,000,000
Short-term Debt [Member] | Parent Company [Member]
Financing (Textual) [Abstract]
Bank Loans																100,000,000
Long-Term Debt And Capital Lease Obligations, Current [Member] | Mississippi Power [Member]
Financing (Textual) [Abstract]
Bank loans outstanding																	425,000,000
Power Purchase Agreement [Member] | Georgia Power [Member]
Financing (Textual) [Abstract]
Capital leased assets, gross																149,000,000	149,000,000
Capitalized lease obligations																$ 141,000,000	148,000,000
Capital Leased Assets, Number of Units | leased_asset_units																2				2
Accumulated depreciation PPE																$ 19,000,000	10,000,000
Power Purchase Agreement [Member] | Georgia Power [Member] | Minimum [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																10.00%				10.00%
Power Purchase Agreement [Member] | Georgia Power [Member] | Maximum [Member]
Financing (Textual) [Abstract]
Fixed stated interest rate of debt obligation																11.00%				11.00%
FFB Loan [Member] | Georgia Power [Member]
Financing (Textual) [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity																$ 2,600,000,000	2,200,000,000
Continuing Letter of Credit Facility [Member] | Southern Power [Member]
Financing (Textual) [Abstract]
Unused credit with banks																82,000,000
Line of Credit Facility, Maximum Borrowing Capacity																120,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member]
Financing (Textual) [Abstract]
Line of Credit Facility, Current Borrowing Capacity																$ 209,000,000	$ 137,000,000
Debt, Weighted Average Interest Rate																2.10%	2.00%			2.10%
Southern Company Gas Capital [Member] | Southern Company Gas [Member]
Debt Instrument [Line Items]
Noncontrolling ownership percentage held by parent																	100.00%
Parent Company [Member] | Mississippi Power [Member]
Financing (Textual) [Abstract]
Promissory Note																$ 551,000,000	$ 576,000,000
Mankato [Member] | Southern Power [Member]
Debt Instrument [Line Items]
Noncontrolling ownership percentage held by parent			100.00%
Financing (Textual) [Abstract]
Life Output Of Plant			10 years													10 years
Mankato Expansion [Member] | Southern Power [Member]
Financing (Textual) [Abstract]
Life Output Of Plant																20 years
Senior Lien [Member] | Southern Power [Member]
Financing (Textual) [Abstract]
Assets																$ 408,000,000

Commitments - Estimated Long-te

Commitments - Estimated Long-term obligations (Details) $ in Millions	Dec. 31, 2016USD ($)
Minimum Lease Payments, Operating Leases [Abstract]
2,017	$ 152
2,018	134
2,019	113
2,020	100
2,021	90
2022 and thereafter	1,195
Total	1,784
Alabama Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	14
2,018	10
2,019	10
2,020	8
2,021	8
2022 and thereafter	10
Total	60
Georgia Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	19
2,018	13
2,019	9
2,020	9
2,021	8
2022 and thereafter	15
Total	73
2,017	225
2,018	218
2,019	220
2,020	216
2,021	219
2022 and thereafter	1,608
Total	2,706
Gulf Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	8
2,018	6
2,019	1
2,020	0
2,021	0
2022 and thereafter	1
Total	16
Southern Company Gas [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	18
2,018	17
2,019	16
2,020	15
2,021	15
2022 and thereafter	38
Total	119
Barges and Rail Cars [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	31
2,018	19
2,019	10
2,020	10
2,021	8
2022 and thereafter	11
Total	89
Barges and Rail Cars [Member] | Georgia Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	12
2,018	6
2,019	3
2,020	3
2,021	2
2022 and thereafter	2
Total	28
Barges and Rail Cars [Member] | Gulf Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	7
2,018	5
2,019	0
2,020	0
2,021	0
2022 and thereafter	0
Total	12
Other Lease Payments [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	121
2,018	115
2,019	103
2,020	90
2,021	82
2022 and thereafter	1,184
Total	1,695
Other Lease Payments [Member] | Georgia Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	7
2,018	7
2,019	6
2,020	6
2,021	6
2022 and thereafter	13
Total	45
Other Lease Payments [Member] | Gulf Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	1
2,018	1
2,019	1
2,020	0
2,021	0
2022 and thereafter	1
Total	4
Railcars [Member] | Alabama Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	10
2,018	7
2,019	7
2,020	6
2,021	6
2022 and thereafter	9
Total	45
Vehicles And Other [Member] | Alabama Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	4
2,018	3
2,019	3
2,020	2
2,021	2
2022 and thereafter	1
Total	15
Purchased Power [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,017	242
2,018	246
2,019	249
2,020	246
2,021	249
2022 and thereafter	1,041
Total	2,273
Purchased Power [Member] | Alabama Power [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,017	40
2,018	41
2,019	43
2,020	44
2,021	46
2022 and thereafter	47
Total	261
Purchased Power [Member] | Gulf Power [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,017	79
2,018	79
2,019	79
2,020	79
2,021	79
2022 and thereafter	112
Total	507
Other Lease Payments [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,017	8
2,018	7
2,019	6
2,020	5
2,021	5
2022 and thereafter	43
Total	74
Affiliate Capital Lease PPA [Member] | Georgia Power [Member]
Minimum Lease Payments, Capital Leases [Abstract]
2,017	22
2,018	22
2,019	23
2,020	23
2,021	24
2022 and thereafter	204
Total	318
Less: amounts representing executory costs	48
Net minimum lease payments	270
Less: amounts representing interest	128
Present value of net minimum lease payments	142
Affiliate Operating Lease PPA [Member] | Georgia Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	72
2,018	63
2,019	64
2,020	65
2,021	66
2022 and thereafter	479
Total	809
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	123
2,018	126
2,019	127
2,020	123
2,021	124
2022 and thereafter	882
Total	1,505
Biomass PPAs Amount	197
Plant Vogtle Nuclear Units One and Two [Member] | Georgia Power [Member]
Minimum Lease Payments, Operating Leases [Abstract]
2,017	8
2,018	7
2,019	6
2,020	5
2,021	5
2022 and thereafter	43
Total	$ 74

Commitments - Textuals (Details

Commitments - Textuals (Details) MMBTU in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016USD ($)MMBTURailcar	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)MMBTURailcar	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013
Recorded Unconditional Purchase Obligation [Line Items]
Fuel expense			$ 4,361,000,000	$ 4,750,000,000	$ 6,005,000,000
Expense under purchase power agreements accounted for as operating leases			232,000,000	227,000,000	198,000,000
Operating leases rent expense			169,000,000	130,000,000	118,000,000
Operating leases, future minimum lease payments due	$ 1,784,000,000		1,784,000,000
Leasing commitment, 2017	152,000,000		152,000,000
Leasing commitment, 2018	134,000,000		134,000,000
Leasing commitment, 2019	113,000,000		113,000,000
Leasing commitment, 2020	100,000,000		100,000,000
Leasing commitment, 2021	90,000,000		90,000,000
Leasing commitment, 2022 and thereafter	1,195,000,000		1,195,000,000
Senior Notes	33,000,000,000		33,000,000,000	19,100,000,000
Barges and Rail Cars [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases, future minimum lease payments due	89,000,000		89,000,000
Leasing commitment, 2017	31,000,000		31,000,000
Leasing commitment, 2018	19,000,000		19,000,000
Leasing commitment, 2019	10,000,000		10,000,000
Leasing commitment, 2020	10,000,000		10,000,000
Leasing commitment, 2021	8,000,000		8,000,000
Leasing commitment, 2022 and thereafter	11,000,000		11,000,000
Mississippi Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Fuel expense			$ 343,000,000	443,000,000	574,000,000
Term of Management Fee Contract			40 years
Management fee	41,000,000		$ 41,000,000
Operating leases rent expense			3,000,000	5,000,000	10,000,000
Long-term pollution control bonds	83,000,000		83,000,000	83,000,000
Senior Notes	$ 790,000,000		$ 790,000,000	1,100,000,000
Number of Railcars Used Under Operating Lease | Railcar	229		229
Company's share of the leases	50.00%		50.00%
Fuel cost recovery clause			$ 2,000,000	2,000,000	3,000,000
Mississippi Power [Member] | Plant Daniel [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Company's share of the leases	50.00%		50.00%
Mississippi Power [Member] | Barges and Rail Cars [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Average leasing commitment, 2015	$ 1,000,000		$ 1,000,000
Alabama Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Fuel expense			1,297,000,000	1,342,000,000	1,605,000,000
Expense under purchase power agreements accounted for as operating leases			42,000,000	38,000,000	37,000,000
Operating leases rent expense			18,000,000	19,000,000	18,000,000
Operating leases, future minimum lease payments due	60,000,000		60,000,000
Leasing commitment, 2017	14,000,000		14,000,000
Leasing commitment, 2018	10,000,000		10,000,000
Leasing commitment, 2019	10,000,000		10,000,000
Leasing commitment, 2020	8,000,000		8,000,000
Leasing commitment, 2021	8,000,000		8,000,000
Leasing commitment, 2022 and thereafter	10,000,000		10,000,000
Long-term pollution control bonds	$ 1,100,000,000		$ 1,100,000,000	1,100,000,000
Percent ownership	14.00%		14.00%
Alabama Power [Member] | Barges and Rail Cars [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases rent expense			$ 14,000,000	13,000,000	14,000,000
Alabama Power [Member] | Residual Value, Leased Property [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Leasing commitment, 2017	$ 0		0
Leasing commitment, 2018	0		0
Leasing commitment, 2019	0		0
Leasing commitment, 2020	0		0
Leasing commitment, 2021	0		0
Leasing commitment, 2022 and thereafter	12,000,000		12,000,000
Georgia Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Fuel expense			1,807,000,000	2,033,000,000	2,547,000,000
Operating leases rent expense			28,000,000	29,000,000	28,000,000
Operating leases, future minimum lease payments due	73,000,000		$ 73,000,000
Period of service for gas transportation supplier			1 year
Maximum guarantee	43,000,000		$ 43,000,000
Leasing commitment, 2017	19,000,000		19,000,000
Leasing commitment, 2018	13,000,000		13,000,000
Leasing commitment, 2019	9,000,000		9,000,000
Leasing commitment, 2020	9,000,000		9,000,000
Leasing commitment, 2021	8,000,000		8,000,000
Leasing commitment, 2022 and thereafter	15,000,000		15,000,000
Long-term pollution control bonds	1,800,000,000		1,800,000,000	1,800,000,000
Senior Notes	6,200,000,000		6,200,000,000	6,300,000,000
Capacity Payments			11,000,000	10,000,000	19,000,000
Deferred capacity expense	$ 217,000,000		$ 217,000,000	203,000,000	167,000,000
Percentage of minimum lease payments			100.00%
Company's share of the leases	50.00%		50.00%
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]
Percent ownership	5.00%		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		$ 25,000,000
Georgia Power [Member] | Alabama Power [Member] | Financial Guarantee [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Senior Notes	100,000,000		100,000,000
Georgia Power [Member] | Barges and Rail Cars [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases, future minimum lease payments due	28,000,000		28,000,000
Leasing commitment, 2017	12,000,000		12,000,000
Leasing commitment, 2018	6,000,000		6,000,000
Leasing commitment, 2019	3,000,000		3,000,000
Leasing commitment, 2020	3,000,000		3,000,000
Leasing commitment, 2021	2,000,000		2,000,000
Leasing commitment, 2022 and thereafter	2,000,000		2,000,000
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		32,000,000
Gulf Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Fuel expense			432,000,000	445,000,000	605,000,000
Expense under purchase power agreements accounted for as operating leases			75,000,000	75,000,000	50,000,000
Operating leases rent expense			9,000,000	14,000,000	15,000,000
Operating leases, future minimum lease payments due	16,000,000		16,000,000
Leasing commitment, 2017	8,000,000		8,000,000
Leasing commitment, 2018	6,000,000		6,000,000
Leasing commitment, 2019	1,000,000		1,000,000
Leasing commitment, 2020	0		0
Leasing commitment, 2021	0		0
Leasing commitment, 2022 and thereafter	1,000,000		1,000,000
Long-term pollution control bonds	309,000,000		309,000,000	309,000,000
Senior Notes	777,000,000		777,000,000	1,010,000,000
Deferred capacity expense	119,000,000		119,000,000	141,000,000
Gulf Power [Member] | Barges and Rail Cars [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases, future minimum lease payments due	12,000,000		12,000,000
Leasing commitment, 2017	7,000,000		7,000,000
Leasing commitment, 2018	5,000,000		5,000,000
Leasing commitment, 2019	0		0
Leasing commitment, 2020	0		0
Leasing commitment, 2021	0		0
Leasing commitment, 2022 and thereafter	0		0
Gulf Power [Member] | Barges and Rail Cars [Member] | Plant Daniel [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Leasing commitment, 2017	2,000,000		2,000,000
Fuel cost recovery clause			2,000,000	2,000,000	3,000,000
Gulf Power [Member] | Barge Transportation [Member] | Plant Crist and Plant Smith [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Leasing commitment, 2017	5,000,000		5,000,000
Leasing commitment, 2018	5,000,000		5,000,000
Fuel cost recovery clause			5,000,000	10,000,000	10,000,000
Southern Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Fuel expense			456,000,000	441,000,000	596,000,000
Operating leases rent expense			22,000,000	7,000,000	4,000,000
Leasing commitment, 2017	18,000,000		18,000,000
Leasing commitment, 2018	19,000,000		19,000,000
Leasing commitment, 2019	20,000,000		20,000,000
Leasing commitment, 2020	20,000,000		20,000,000
Leasing commitment, 2021	20,000,000		20,000,000
Leasing commitment, 2022 and thereafter	762,000,000		762,000,000
Senior Notes	5,300,000,000		5,300,000,000	2,700,000,000
Southern Company Gas [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases, future minimum lease payments due	119,000,000		119,000,000
Leasing commitment, 2017	18,000,000		18,000,000
Leasing commitment, 2018	17,000,000		17,000,000
Leasing commitment, 2019	16,000,000		16,000,000
Leasing commitment, 2020	15,000,000		15,000,000
Leasing commitment, 2021	15,000,000		15,000,000
Leasing commitment, 2022 and thereafter	38,000,000		38,000,000
Senior Notes	3,700,000,000		3,700,000,000	2,500,000,000
Alabama Power and Georgia Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases, future minimum lease payments due	44,000,000		44,000,000
Tropic Equipment Leasing Inc [Member] | Financial Guarantee [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Maximum guarantee	$ 1,000,000		$ 1,000,000
Nicor Gas and Southstar [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Natural gas pipeline capacity | MMBTU	33		33
Long-term purchase commitment amount			$ 106,000,000
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases, future minimum lease payments due	$ 1,505,000,000		1,505,000,000
Leasing commitment, 2017	123,000,000		123,000,000
Leasing commitment, 2018	126,000,000		126,000,000
Leasing commitment, 2019	127,000,000		127,000,000
Leasing commitment, 2020	123,000,000		123,000,000
Leasing commitment, 2021	124,000,000		124,000,000
Leasing commitment, 2022 and thereafter	882,000,000		$ 882,000,000
Successor [Member] | Southern Company Gas [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases rent expense	$ 8,000,000
Predecessor [Member] | Southern Company Gas [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Operating leases rent expense		$ 6,000,000		$ 12,000,000	$ 13,000,000

Commitments - Contractual Oblig

Commitments - Contractual Obligations - Pipeline Charges, Storage Capacity, and Gas Supply (Details) - Pipeline Charges Storage Capacity And Gas Supply [Member] $ in Millions	Dec. 31, 2016USD ($)
Long-term Purchase Commitment [Line Items]
2,017	$ 822
2,018	602
2,019	447
2,020	394
2,021	352
2022 and thereafter	2,591
Total	5,208
Southern Company Gas [Member]
Long-term Purchase Commitment [Line Items]
Total	$ 5,208

Common Stock and Stock Compe102

Common Stock and Stock Compensation - Textual Stock Issued, Reserved, Employee (Details) $ / shares in Units, shares in Thousands, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2015USD ($)	Dec. 31, 2016USD ($)Employeeshares	Dec. 31, 2016USD ($)Employeeshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Jul. 01, 2016$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issuances | $			$ 3,758	$ 256	$ 806
Common stock fees and commissions | $		$ 3
Stock issued employee and director stock plans			20,000
Proceeds from issuance of shares under share-based compensation plans | $			$ 874
Number of shares reserved for issuance to stock-based compensation plan			94,000
Number of employees participating in stock-based compensation plans | Employee		5,229	5,229
Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued, shares			76,140	6,571	15,769
Treasury Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued, shares			2,599	(2,599)	4,996
Underwritten Offerings [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued, shares			50,800
Common stock issuances | $			$ 2,500
Underwritten Offerings [Member] | Treasury Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued, shares			2,600
At-The-Market [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued, shares		8,000
Common stock issuances | $		$ 381
Southern Company Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining shares available for awards		14,000	14,000
Alabama Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of employees participating in stock-based compensation plans | Employee		865	865
Georgia Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of employees participating in stock-based compensation plans | Employee		990	990
Gulf Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issuances | $	$ 20		$ 0	$ 20	$ 50
Number of employees participating in stock-based compensation plans | Employee		184	184
Gulf Power [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued, shares				1,000	0
Mississippi Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of employees participating in stock-based compensation plans | Employee		220	220
Southern Company [Member] | Southern Company Gas [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Business acquisition share price (in dollars per share) | $ / shares						$ 66

Common Stock and Stock Compe103

Common Stock and Stock Compensation - Textual Stock Options (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining contractual term for options outstanding	6 years
Weighted average remaining contractual term for options exercisable	5 years
Aggregate intrinsic value for options outstanding	$ 195
Aggregate intrinsic value for options exercisable	168
Total compensation cost for award recognized in income	3	$ 6	$ 27
Total compensation cost for award recognized in income, tax benefit	1	2	10
Total intrinsic value of options exercised	120	48	125
Actual tax benefit for the tax deduction from stock option exercised	46	19	48
Cash received from issuance related to option exercise	$ 448	$ 154	$ 400
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value (in dollars per share)			$ 2.20
Option expiration period from date of grant	10 years
Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award exercisable period	3 years
Gulf Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value assumptions weighted average grant date fair value (in dollars per share)		$ 2.20
Aggregate intrinsic value for options outstanding	$ 6
Aggregate intrinsic value for options exercisable	5
Total intrinsic value of options exercised	3	$ 2	$ 5
Actual tax benefit for the tax deduction from stock option exercised	$ 1		2
Gulf Power [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option expiration period from date of grant	10 years
Gulf Power [Member] | Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award exercisable period	3 years
Georgia Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value for options outstanding	$ 46
Aggregate intrinsic value for options exercisable	41
Total intrinsic value of options exercised	18	9	19
Actual tax benefit for the tax deduction from stock option exercised	$ 7	$ 4	7
Georgia Power [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value (in dollars per share)		$ 2.20
Option expiration period from date of grant	10 years
Georgia Power [Member] | Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award exercisable period	3 years
Alabama Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value for options outstanding	$ 30
Aggregate intrinsic value for options exercisable	26
Total intrinsic value of options exercised	21	$ 8	21
Actual tax benefit for the tax deduction from stock option exercised	$ 8	3	$ 8
Alabama Power [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value (in dollars per share)			$ 2.20
Option expiration period from date of grant	10 years
Alabama Power [Member] | Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award exercisable period	3 years
Mississippi Power [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value (in dollars per share)			$ 2.20
Option expiration period from date of grant	10 years
Aggregate intrinsic value for options outstanding	$ 6
Aggregate intrinsic value for options exercisable	5
Total intrinsic value of options exercised	4	3	$ 5
Actual tax benefit for the tax deduction from stock option exercised	$ 2	$ 1	$ 2
Mississippi Power [Member] | Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award exercisable period	3 years

Common Stock and Stock Compe104

Common Stock and Stock Compensation - Table Stock Options, Assumptions Used (Details) - Stock Options [Member]	12 Months Ended
	Dec. 31, 2014$ / shares
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted
Expected volatility	14.60%
Expected term (in years)	5 years
Interest rate	1.50%
Dividend yield, percentage	4.90%
Weighted average grant-date fair value (in dollars per share)	$ 2.20

Common Stock and Stock Compe105

Common Stock and Stock Compensation - Table Stock Option Activity (Details)	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Shares Subject to Option (in shares):
Outstanding, Beginning Balance (in shares) | shares	35,749,906
Exercised (in shares) | shares	11,120,613
Cancelled (in shares) | shares	43,429
Outstanding, Ending Balance (in shares) | shares	24,585,864
Exercisable, Ending Balance (in shares) | shares	21,133,320
Weighted Average Exercise Price (in dollars per share):
Outstanding, Weighted Average Exercise Price, Beginning of Period (in dollars per share) | $ / shares	$ 40.96
Exercised, Weighted Average Exercise Price (in dollars per share) | $ / shares	40.26
Cancelled, Weighted Average Exercise Price (in dollars per share) | $ / shares	41.38
Outstanding, Weighted Average Exercise Price, End of Period (in dollars per share) | $ / shares	41.28
Exercisable, Weighted Average Exercise Price, End of Period (in dollars per share) | $ / shares	$ 41.26

Common Stock and Stock Compe106

Common Stock and Stock Compensation - Textual Performance Shares (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)share_unit_type$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	0.00%
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	200.00%
Total compensation cost for award recognized in income	$ 3	$ 6	$ 27
Total compensation cost for award recognized in income, tax benefit	$ 1	$ 2	10
EPS-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance share units issued under Performance Share Plan	3 years
Performance share units, unvested (in shares) | shares	3,224,539	2,480,392
Vested and expected to best (in shares) | shares	0
Equity instrument, granted (in shares) | shares	1,717,167
Equity instruments, vested (in shares) | shares	937,121
Equity instruments, forfeited (in shares) | shares	35,899
Total compensation cost for award recognized in income	$ 96	$ 88	33
Total compensation cost for award recognized in income, tax benefit	37	$ 34	$ 13
Total unrecognized compensation cost related to award	$ 32
Total unrecognized compensation cost related to award, weighted average period	22 months
EPS-based and ROE-based Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of additional types of performance share units | share_unit_type	2
Initial assumed percentage payout at end of performance period	100.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 48.87	$ 47.75
ROE-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
TSR-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	50.00%
Alabama Power [Member] | EPS-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Alabama Power [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance share units issued under Performance Share Plan	3 years
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	0.00%
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	200.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 45.15	$ 46.42	$ 37.54
Equity instrument, granted (in shares) | shares	249,065	214,709	176,070
Total compensation cost for award recognized in income	$ 15	$ 13	$ 5
Total compensation cost for award recognized in income, tax benefit	6	$ 5	$ 2
Total unrecognized compensation cost related to award	$ 3
Total unrecognized compensation cost related to award, weighted average period	22 months
Alabama Power [Member] | EPS-based and ROE-based Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of additional types of performance share units | share_unit_type	2
Initial assumed percentage payout at end of performance period	100.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 48.86	$ 47.78
Alabama Power [Member] | ROE-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Alabama Power [Member] | TSR-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	50.00%
Georgia Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance share units issued under Performance Share Plan	3 years
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	0.00%
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	200.00%
Georgia Power [Member] | EPS-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Georgia Power [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 45.17	$ 46.41	$ 37.54
Equity instrument, granted (in shares) | shares	261,434	236,804	176,224
Total compensation cost for award recognized in income	$ 15	$ 15	$ 6
Total compensation cost for award recognized in income, tax benefit	6	$ 6	$ 2
Total unrecognized compensation cost related to award	$ 4
Total unrecognized compensation cost related to award, weighted average period	22 months
Georgia Power [Member] | EPS-based and ROE-based Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of additional types of performance share units | share_unit_type	2
Initial assumed percentage payout at end of performance period	100.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 48.84	$ 47.78
Georgia Power [Member] | ROE-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Georgia Power [Member] | TSR-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	50.00%
Gulf Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance share units issued under Performance Share Plan	3 years
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	0.00%
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	200.00%
Fair value assumptions weighted average grant date fair value (in dollars per share) | $ / shares		$ 2.20
Gulf Power [Member] | EPS-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Gulf Power [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instrument, granted (in shares) | shares	57,333	48,962	37,829
Fair value assumptions weighted average grant date fair value (in dollars per share) | $ / shares	$ 45.18	$ 46.38	$ 37.54
Total compensation cost for award recognized in income	$ 3	$ 2	$ 1
Total compensation cost for award recognized in income, tax benefit	1
Total unrecognized compensation cost related to award	$ 2
Total unrecognized compensation cost related to award, weighted average period	22 months
Gulf Power [Member] | EPS-based and ROE-based Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of additional types of performance share units | share_unit_type	2
Initial assumed percentage payout at end of performance period	100.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 48.83	$ 47.75
Gulf Power [Member] | ROE-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Gulf Power [Member] | TSR-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	50.00%
Mississippi Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance share units issued under Performance Share Plan	3 years
Mississippi Power [Member] | EPS-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Mississippi Power [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	0.00%
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	200.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 45.17	$ 46.41	$ 37.54
Equity instrument, granted (in shares) | shares	62,435	53,909	49,579
Total compensation cost for award recognized in income	$ 4	$ 4	$ 2
Total compensation cost for award recognized in income, tax benefit	1	$ 2	$ 1
Total unrecognized compensation cost related to award	$ 1
Total unrecognized compensation cost related to award, weighted average period	22 months
Mississippi Power [Member] | EPS-based and ROE-based Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of additional types of performance share units | share_unit_type	2
Initial assumed percentage payout at end of performance period	100.00%
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares	$ 48.84	$ 47.77
Mississippi Power [Member] | ROE-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	25.00%
Mississippi Power [Member] | TSR-based Portion Of The Performance Share Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of total performance share units granted	50.00%

Common Stock and Stock Compe107

Common Stock and Stock Compensation - Table Performance Shares, Assumptions Used (Details) - Performance Shares [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility	15.00%	12.90%	12.60%
Expected term (in years)	3 years	3 years	3 years
Interest rate	0.80%	1.00%	0.60%
Dividend yield			$ 2.03
Weighted average grant-date fair value (in dollars per share)	$ 45.06	$ 46.38	$ 37.54
Vesting period of performance share units issued under Performance Share Plan	3 years

Common Stock and Stock Compe108

Common Stock and Stock Compensation - Textual Southern Company Gas Awards (Details)	6 Months Ended		12 Months Ended
	Dec. 31, 2016USD ($)shares	Jun. 30, 2016USD ($)shares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)performance_measure$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Jul. 01, 2016$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost for award recognized in income				$ 3,000,000	$ 6,000,000	$ 27,000,000
Tax credit carryforward	$ 1,800,000,000			$ 1,800,000,000
Shares vested and issued each year employee remains in service				0.33%
Aggregate intrinsic value for options outstanding	$ 195,000,000			$ 195,000,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instrument, granted (in shares) | shares				1,717,167
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares	3,224,539			3,224,539	2,480,392
Total compensation cost for award recognized in income				$ 96,000,000	$ 88,000,000	$ 33,000,000
Total unrecognized compensation cost related to award, weighted average period				22 months
Equity instruments, vested (in shares) | shares				937,121
Equity instruments, forfeited (in shares) | shares				35,899
Parent Company [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instrument, granted (in shares) | shares	742,461
Equity instrument granted in period, weighted average grant date fair value (in dollars per share) | $ / shares				$ 53.83
Merger-related expenses				$ 13,000,000
Parent Company [Member] | Scenario, Forecast [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost for award recognized in income			$ 12,000,000
Southern Company Gas [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vested and issued each year employee remains in service				0.33%
Southern Company Gas [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award requisite service period				3 years
Equity instrument, granted (in shares) | shares		25,166			47,546	44,272
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares							65,042
Total compensation cost for award recognized in income				$ 13,000,000
Tax credit carryforward	$ 4,000,000			4,000,000
Compensation not yet recognized	12,000,000			$ 12,000,000
Total unrecognized compensation cost related to award, weighted average period				20 months
Southern Company Gas [Member] | Change In Control Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation not yet recognized	20,000,000			$ 20,000,000
Total unrecognized compensation cost related to award, weighted average period				23 months
Southern Company Gas [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award requisite service period				3 years
Expiration period				10 years
Southern Company Gas [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of performance criteria | performance_measure				2
Performance measure one, % of award					75.00%
Performance measure two, % of award					25.00%
Performance period					3 years
Southern Company Gas [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instrument, granted (in shares) | shares				303,618
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares					398,832
Equity instruments, vested (in shares) | shares				699,960
Equity instruments, forfeited (in shares) | shares				2,466
Southern Company Gas [Member] | Successor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Merger-related expenses	41,000,000
Southern Company Gas [Member] | Successor [Member] | Change In Control Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost for award recognized in income				$ 4,000,000
Tax credit carryforward	$ 1,000,000			$ 1,000,000
Southern Company Gas [Member] | Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Merger-related expenses		$ 56,000,000			$ 44,000,000	$ 0
Compensation not yet recognized					0
Proceeds from stock options exercised		1,000,000			5,000,000
Aggregate intrinsic value for options outstanding		3,000,000			13,000,000	4,000,000
Southern Company Gas [Member] | Predecessor [Member] | Cash and Stock-based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost for award recognized in income		$ 24,000,000			$ 40,000,000	$ 24,000,000
Southern Company Gas [Member] | Minimum [Member] | Change In Control Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares to common stock based on price metrics and performance goals				0.00%
Southern Company Gas [Member] | Maximum [Member] | Change In Control Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares to common stock based on price metrics and performance goals				100.00%
Omnibus Performance Incentive Plan [Member] | Southern Company Gas [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining shares available for awards | shares					359,586
Number of shares authorized | shares					3,513,992
Long Term Incentive Plan [Member] | Southern Company Gas [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining shares available for awards | shares					80,600
Long Term Incentive Plan [Member] | Nicor Gas [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining shares available for awards | shares					1,514,116
Southern Company [Member] | Southern Company Gas [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Business acquisition share price (in dollars per share) | $ / shares							$ 66
Conversion ratio, percentage of underlying stock award units							125.00%

Common Stock and Stock Compe109

Common Stock and Stock Compensation - Table Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings per share (EPS) —
As reported shares	951	910	897
Effect of options	7	4	4
Diluted shares	958	914	901

Common Stock and Stock Compe110

Common Stock and Stock Compensation - Textual Dividend Restrictions (Details) $ in Billions	12 Months Ended
	Dec. 31, 2016USD ($)
Equity [Abstract]
Undistributed retained earnings of the subsidiaries	$ 7

Nuclear Insurance (Details)

Nuclear Insurance (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2014	Dec. 31, 2016
Jointly Owned Utility Plant Interests [Line Items]
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act		$ 13,400
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		13,400
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		26 weeks
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		53
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		$ 13,400
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		$ 82
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, 2016	Dec. 31, 2015
Liabilities:
Weather Derivative Premium	$ 4
Collateral already posted, aggregate fair value	62
Energy-related derivatives
Liabilities:
Collateral already posted, aggregate fair value	8
Recurring
Assets:
Interest rate derivatives	14	$ 22
Nuclear decommissioning trusts:
Cash equivalents	1,172	790
Other investments	10	10
Fair value assets, total	3,471	2,338
Liabilities:
Interest rate derivatives	29	30
Contingent consideration	18
Fair value liabilities, total	735	250
Recurring | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	662	610
Recurring | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	216	207
Recurring | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	92	152
Recurring | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	73	64
Recurring | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	332	289
Recurring | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	183	145
Recurring | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	20	17
Recurring | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	26	25
Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	671	7
Liabilities:
Liability Derivatives	630	220
Recurring | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	58
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Interest rate derivatives	0	0
Nuclear decommissioning trusts:
Cash equivalents	1,172	790
Other investments	9	9
Fair value assets, total	2,189	1,414
Liabilities:
Interest rate derivatives	0	0
Contingent consideration	0
Fair value liabilities, total	345	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	589	541
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	48	47
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	22	11
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	11	16
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	338	0
Liabilities:
Liability Derivatives	345	0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	0
Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Interest rate derivatives	14	22
Nuclear decommissioning trusts:
Cash equivalents	0	0
Other investments	0	0
Fair value assets, total	1,261	906
Liabilities:
Interest rate derivatives	29	30
Contingent consideration	0
Fair value liabilities, total	372	250
Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	73	69
Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	168	160
Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	92	152
Recurring | Significant Other Observable Inputs (Level 2) | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	73	64
Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	310	278
Recurring | Significant Other Observable Inputs (Level 2) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	183	145
Recurring | Significant Other Observable Inputs (Level 2) | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Other Observable Inputs (Level 2) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	15	9
Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	333	7
Liabilities:
Liability Derivatives	285	220
Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	58
Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Interest rate derivatives	0	0
Nuclear decommissioning trusts:
Cash equivalents	0	0
Other investments	1	1
Fair value assets, total	1	1
Liabilities:
Interest rate derivatives	0	0
Contingent consideration	18
Fair value liabilities, total	18	0
Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0	0
Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	0
Alabama Power [Member]
Assets:
Energy-related derivatives	20	1
Liabilities:
Liability Derivatives	9	70
Alabama Power [Member] | Recurring
Nuclear decommissioning trusts:
Nuclear decommissioning trusts, NAV	20	17
Cash equivalents	262	68
Fair value assets, total	1,072	803
Liabilities:
Liability Derivatives		70
Alabama Power [Member] | Recurring | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	457	427
Alabama Power [Member] | Recurring | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	95	94
Alabama Power [Member] | Recurring | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	21	27
Alabama Power [Member] | Recurring | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	168	146
Alabama Power [Member] | Recurring | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	19	18
Alabama Power [Member] | Recurring | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	20	17
Nuclear decommissioning trusts, NAV	20	17
Alabama Power [Member] | Recurring | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	10	5
Alabama Power [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	20	1
Liabilities:
Liability Derivatives	9	55
Alabama Power [Member] | Recurring | Interest rate derivatives
Liabilities:
Liability Derivatives		15
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Nuclear decommissioning trusts:
Cash equivalents	262	68
Fair value assets, total	717	485
Liabilities:
Liability Derivatives		0
Interest rate derivatives		0
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	385	359
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	48	47
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	22	11
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0
Alabama Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivatives
Liabilities:
Liability Derivatives		0
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2)
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	335	301
Liabilities:
Liability Derivatives		70
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	72	68
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	47	47
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	21	27
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	146	135
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	19	18
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	10	5
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	20	1
Liabilities:
Liability Derivatives	9	55
Alabama Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Interest rate derivatives
Liabilities:
Liability Derivatives		15
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3)
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	0	0
Liabilities:
Liability Derivatives		0
Interest rate derivatives		0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0
Alabama Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Interest rate derivatives
Liabilities:
Liability Derivatives		0
Georgia Power [Member]
Assets:
Energy-related derivatives	46	7
Liabilities:
Liability Derivatives	11	21
Georgia Power [Member] | Recurring
Assets:
Interest rate derivatives		5
Nuclear decommissioning trusts:
Nuclear decommissioning trusts		63
Cash equivalents		845
Fair value assets, total	860
Liabilities:
Liability Derivatives	11	21
Georgia Power [Member] | Recurring | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	205	183
Georgia Power [Member] | Recurring | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	121	113
Georgia Power [Member] | Recurring | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	71	125
Georgia Power [Member] | Recurring | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	73	64
Georgia Power [Member] | Recurring | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	164	143
Georgia Power [Member] | Recurring | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	164	127
Georgia Power [Member] | Recurring | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	16	20
Georgia Power [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	44	2
Liabilities:
Liability Derivatives	8	15
Georgia Power [Member] | Recurring | Interest rate derivatives
Assets:
Interest rate derivatives	2
Liabilities:
Liability Derivatives	3	6
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Interest rate derivatives		0
Nuclear decommissioning trusts:
Cash equivalents	63	261
Fair value assets, total	215
Liabilities:
Liability Derivatives	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	204	182
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	11	16
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0	0
Georgia Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivatives
Assets:
Interest rate derivatives	0
Liabilities:
Liability Derivatives	0	0
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Interest rate derivatives		5
Nuclear decommissioning trusts:
Cash equivalents	0	584
Fair value assets, total	645
Liabilities:
Liability Derivatives	11	21
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	1	1
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	121	113
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	71	125
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	73	64
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	164	143
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	164	127
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	5	4
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	44	2
Liabilities:
Liability Derivatives	8	15
Georgia Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Interest rate derivatives
Assets:
Interest rate derivatives	2
Liabilities:
Liability Derivatives	3	6
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Interest rate derivatives		0
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	0
Liabilities:
Liability Derivatives	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Municipal bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Mortgage- and asset-backed securities
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Other
Nuclear decommissioning trusts:
Nuclear decommissioning trusts	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0	0
Georgia Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Interest rate derivatives
Assets:
Interest rate derivatives	0
Liabilities:
Liability Derivatives	0	0
Gulf Power [Member]
Assets:
Energy-related derivatives	5	1
Liabilities:
Liability Derivatives	29	100
Gulf Power [Member] | Recurring
Assets:
Interest rate derivatives		1
Nuclear decommissioning trusts:
Cash equivalents	20	18
Fair value assets, total	25	19
Gulf Power [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	5
Liabilities:
Liability Derivatives	29	100
Gulf Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Interest rate derivatives		0
Nuclear decommissioning trusts:
Cash equivalents	20	18
Fair value assets, total	20	18
Gulf Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	0
Liabilities:
Liability Derivatives	0	0
Gulf Power [Member] | Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Interest rate derivatives		1
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	5	1
Gulf Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	5
Liabilities:
Liability Derivatives	29	100
Gulf Power [Member] | Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Interest rate derivatives		0
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	0	0
Gulf Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0
Liabilities:
Liability Derivatives	0	0
Mississippi Power [Member]
Assets:
Energy-related derivatives	7	0
Liabilities:
Liability Derivatives	11	47
Mississippi Power [Member] | Recurring
Nuclear decommissioning trusts:
Cash equivalents	206	52
Fair value assets, total	212
Mississippi Power [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	3
Liabilities:
Liability Derivatives	10	47
Mississippi Power [Member] | Recurring | Interest rate derivatives
Assets:
Interest rate derivatives	3
Mississippi Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Nuclear decommissioning trusts:
Cash equivalents	206	52
Fair value assets, total	206
Mississippi Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	0
Liabilities:
Liability Derivatives	0	0
Mississippi Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivatives
Assets:
Interest rate derivatives	0
Mississippi Power [Member] | Recurring | Significant Other Observable Inputs (Level 2)
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	6
Mississippi Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	3
Liabilities:
Liability Derivatives	10	47
Mississippi Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Interest rate derivatives
Assets:
Interest rate derivatives	3
Mississippi Power [Member] | Recurring | Significant Unobservable Inputs (Level 3)
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	0
Mississippi Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0
Liabilities:
Liability Derivatives	0	0
Mississippi Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Interest rate derivatives
Assets:
Interest rate derivatives	0
Southern Power [Member] | Recurring
Assets:
Interest rate derivatives	1	3
Nuclear decommissioning trusts:
Cash equivalents	628	511
Fair value assets, total	650	518
Liabilities:
Contingent consideration	18
Fair value liabilities, total	81
Southern Power [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	21	4
Liabilities:
Liability Derivatives	5	3
Southern Power [Member] | Recurring | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	58
Southern Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Interest rate derivatives	0	0
Nuclear decommissioning trusts:
Cash equivalents	628	511
Fair value assets, total	628	511
Liabilities:
Contingent consideration	0
Fair value liabilities, total	0
Southern Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0	0
Southern Power [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	0
Southern Power [Member] | Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Interest rate derivatives	1	3
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	22	7
Liabilities:
Contingent consideration	0
Fair value liabilities, total	63
Southern Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	21	4
Liabilities:
Liability Derivatives	5	3
Southern Power [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	58
Southern Power [Member] | Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Interest rate derivatives	0	0
Nuclear decommissioning trusts:
Cash equivalents	0	0
Fair value assets, total	0	0
Liabilities:
Contingent consideration	18
Fair value liabilities, total	18
Southern Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0	0
Liabilities:
Liability Derivatives	0	0
Southern Power [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Foreign currency derivatives
Liabilities:
Foreign currency derivatives	0
Predecessor [Member] | Southern Company Gas [Member]
Assets:
Energy-related derivatives		942
Liabilities:
Liability Derivatives		866
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Liabilities:
Collateral already posted, aggregate fair value		19
Predecessor [Member] | Southern Company Gas [Member] | Recurring
Assets:
Energy-related derivatives		175
Interest rate derivatives		9
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives		166
Liabilities:
Liability Derivatives		109
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives		53
Interest rate derivatives		0
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives		53
Liabilities:
Liability Derivatives		63
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives		122
Interest rate derivatives		9
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives		113
Liabilities:
Liability Derivatives		46
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives		0
Interest rate derivatives		0
Predecessor [Member] | Southern Company Gas [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives		0
Liabilities:
Liability Derivatives		0
Successor [Member] | Southern Company Gas [Member]
Assets:
Energy-related derivatives	581
Liabilities:
Liability Derivatives	569
Weather Derivative Premium	4	10
Collateral already posted, aggregate fair value	62	96
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Liabilities:
Collateral already posted, aggregate fair value	8
Successor [Member] | Southern Company Gas [Member] | Recurring | Energy-related derivatives
Assets:
Energy-related derivatives	577
Liabilities:
Liability Derivatives	569
Successor [Member] | Southern Company Gas [Member] | Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Energy-related derivatives
Assets:
Energy-related derivatives	338
Liabilities:
Liability Derivatives	345
Successor [Member] | Southern Company Gas [Member] | Recurring | Significant Other Observable Inputs (Level 2) | Energy-related derivatives
Assets:
Energy-related derivatives	239
Liabilities:
Liability Derivatives	224
Successor [Member] | Southern Company Gas [Member] | Recurring | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Assets:
Energy-related derivatives	0
Liabilities:
Liability Derivatives	0
Nuclear Decommissioning Trusts [Member] | Recurring
Nuclear decommissioning trusts:
Fair value assets, total	20	17
Nuclear Decommissioning Trusts [Member] | Recurring | Private equity
Nuclear decommissioning trusts:
Nuclear decommissioning trusts, NAV	$ 20	$ 17

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value, Nature and Risk of Investments (Details) - Private equity - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 20	$ 17
Unfunded Commitments	25	28
Alabama Power [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	20	17
Unfunded Commitments	$ 25	$ 28

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments, Carrying Amount Not Equal to Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	$ 45,080	$ 27,216
Long-term debt, Fair Value	46,286	27,913
Alabama Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	7,092	6,849
Long-term debt, Fair Value	7,544	7,192
Georgia Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	10,516	10,145
Long-term debt, Fair Value	11,034	10,480
Gulf Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	1,074	1,303
Long-term debt, Fair Value	1,097	1,339
Mississippi Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	2,979	2,537
Long-term debt, Fair Value	2,922	2,413
Southern Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	5,628	3,122
Long-term debt, Fair Value	5,691	3,117
Successor [Member] | Southern Company Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount	5,281
Long-term debt, Fair Value	$ 5,491
Predecessor [Member] | Southern Company Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Amount		3,820
Long-term debt, Fair Value		$ 4,066

Fair Value Measurements - Textu

Fair Value Measurements - Textual (Details)	12 Months Ended
	Dec. 31, 2016
Southern Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Contingent payment obligations, payment period	10 years
Private equity
Fair Value, Option, Quantitative Disclosures [Line Items]
Entities that calculation NAV, liquidation investment, remaining period	10 years

Derivatives - Interest Rate Der

Derivatives - Interest Rate Derivatives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Derivative [Line Items]
Notional Amount	$ 4,027
Fair Value Gain Loss	(14)
Maturity Date November 2025 [Member] | Cash Flow Hedges of Forecasted Debt
Derivative [Line Items]
Notional Amount	$ 80
Notional Amount of Interest Rate Derivatives Interest Rate Paid	2.32%
Interest Rate Received	3-month LIBOR
Hedge Maturity Date	Dec. 15, 2026
Fair Value Gain Loss	$ 0
Maturity Date March 2018 [Member] | Cash Flow Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 900
Notional Amount of Interest Rate Derivatives Interest Rate Paid	0.79%
Interest Rate Received	1-month LIBOR
Hedge Maturity Date	Mar. 1, 2018
Fair Value Gain Loss	$ 3
Maturity Date August 2017 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 250
Notional Amount of Interest Rate Derivatives Interest Rate Received	1.30%
Interest Rate Received	3-month LIBOR + 0.17%
Basis Spread on Variable Rate	0.17%
Hedge Maturity Date	Aug. 15, 2017
Fair Value Gain Loss	$ 0
Maturity Date June 2018 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 250
Notional Amount of Interest Rate Derivatives Interest Rate Received	5.40%
Interest Rate Received	3-month LIBOR + 4.02%
Basis Spread on Variable Rate	4.02%
Hedge Maturity Date	Jun. 1, 2018
Fair Value Gain Loss	$ 0
Maturity Date December 2018 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 500
Notional Amount of Interest Rate Derivatives Interest Rate Received	1.95%
Interest Rate Received	3-month LIBOR + 0.76%
Basis Spread on Variable Rate	0.76%
Hedge Maturity Date	Dec. 1, 2018
Fair Value Gain Loss	$ (2)
Maturity Date December 2019 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 200
Notional Amount of Interest Rate Derivatives Interest Rate Received	4.25%
Interest Rate Received	3-month LIBOR + 2.46%
Basis Spread on Variable Rate	2.46%
Hedge Maturity Date	Dec. 1, 2019
Fair Value Gain Loss	$ 1
Maturity Date June 2020 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 300
Notional Amount of Interest Rate Derivatives Interest Rate Received	2.75%
Interest Rate Received	3-month LIBOR + 0.92%
Basis Spread on Variable Rate	0.92%
Hedge Maturity Date	Jun. 15, 2020
Fair Value Gain Loss	$ 1
Maturity Date June 2021 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 1,500
Notional Amount of Interest Rate Derivatives Interest Rate Received	2.35%
Interest Rate Received	1-month LIBOR + 0.87%
Basis Spread on Variable Rate	0.87%
Hedge Maturity Date	Jul. 1, 2021
Fair Value Gain Loss	$ (18)
Georgia Power [Member]
Derivative [Line Items]
Notional Amount	950
Fair Value Gain Loss	(1)
Georgia Power [Member] | Maturity Date June 2018 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 250
Notional Amount of Interest Rate Derivatives Interest Rate Paid	5.40%
Interest Rate Received	3-month LIBOR + 4.02%
Basis Spread on Variable Rate	4.02%
Hedge Maturity Date	Jun. 1, 2018
Fair Value Gain Loss	$ 0
Georgia Power [Member] | Maturity Date December 2018 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 500
Notional Amount of Interest Rate Derivatives Interest Rate Paid	1.95%
Interest Rate Received	3-month LIBOR + 0.76%
Basis Spread on Variable Rate	0.76%
Hedge Maturity Date	Dec. 1, 2018
Fair Value Gain Loss	$ (2)
Georgia Power [Member] | Maturity Date December 2019 [Member] | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 200
Notional Amount of Interest Rate Derivatives Interest Rate Paid	4.25%
Interest Rate Received	3-month LIBOR + 2.46%
Basis Spread on Variable Rate	2.46%
Hedge Maturity Date	Dec. 1, 2019
Fair Value Gain Loss	$ 1
Gulf Power [Member] | Maturity Date December 2026 [Member] | Cash Flow Hedges of Forecasted Debt
Derivative [Line Items]
Notional Amount	$ 80
Notional Amount of Interest Rate Derivatives Interest Rate Paid	2.32%
Interest Rate Received	3-month LIBOR
Hedge Maturity Date	Dec. 1, 2026
Fair Value Gain Loss	$ 0
Mississippi Power [Member] | Maturity Date March 2018 [Member] | Cash Flow Hedges of Existing Debt | Interest rate derivatives
Derivative [Line Items]
Notional Amount	$ 900
Notional Amount of Interest Rate Derivatives Interest Rate Paid	0.79%
Fair Value Gain Loss	$ 3
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Maturity Date October 2016 [Member]
Derivative [Line Items]
Term of contract	15 years
RE Tranquility Holdings, LLC [Member] | Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Maturity Date January 2017 [Member]
Derivative [Line Items]
Hedge Maturity Date	Jan. 31, 2017
RE Roserock Holdings, LLC [Member] | Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Maturity Date January 2017 [Member]
Derivative [Line Items]
Notional Amount	$ 47
Notional Amount of Interest Rate Derivatives Interest Rate Paid	2.21%
Interest Rate Received	3-month LIBOR
Fair Value Gain Loss	$ 1

Derivatives - Foreign Currency

Derivatives - Foreign Currency Derivatives (Details) - 12 months ended Dec. 31, 2016 € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Fair Value Gain Loss	$ (14)
Foreign currency derivatives | Cash Flow Hedges of Existing Debt
Derivative [Line Items]
Pay Notional	1,241
Receive Notional | €		€ 1,100
Fair Value Gain Loss	(58)
Southern Power [Member] | Foreign currency derivatives | Maturity Date June 2022 [Member] | Cash Flow Hedges of Existing Debt
Derivative [Line Items]
Pay Notional	$ 677
Pay Rate	2.95%
Receive Notional | €		600
Receive Rate	1.00%
Fair Value Gain Loss	$ (34)
Southern Power [Member] | Foreign currency derivatives | Maturity Date June 2026 [Member] | Cash Flow Hedges of Existing Debt
Derivative [Line Items]
Pay Notional	$ 564
Pay Rate	3.78%
Receive Notional | €		€ 500
Receive Rate	1.85%
Fair Value Gain Loss	$ (24)

Derivatives - Financial Stateme

Derivatives - Financial Statement Presentation (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair value of energy-related derivatives and interest rate derivatives
Collateral already posted, aggregate fair value	$ 62
Energy-related derivatives
Fair value of energy-related derivatives and interest rate derivatives
Collateral already posted, aggregate fair value	8
Parent Company [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	690	$ 29
Derivative asset, gross amount offset	(462)	(15)
Derivative Asset	228	14
Derivative liability, gross	718	250
Derivative liability, gross amounts offset	(524)	(15)
Derivative Liability	194	235
Parent Company [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	556	4
Derivative liability, gross	564	1
Parent Company [Member] | Energy-related derivatives | Other current assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	489	1
Parent Company [Member] | Energy-related derivatives | Liabilities from risk management activities, net of collateral [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	483	1
Parent Company [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	66	0
Parent Company [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	81	0
Parent Company [Member] | Interest rate derivatives | Other current assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	1	3
Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	20	1
Derivative asset, gross amount offset	(8)	(1)
Derivative Asset	12	0
Derivative liability, gross	9	70
Derivative liability, gross amounts offset	(8)	(1)
Derivative Liability	1	69
Georgia Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	46	7
Derivative asset, gross amount offset	(8)	(6)
Derivative Asset	38	1
Derivative liability, gross	11	21
Derivative liability, gross amounts offset	(8)	(6)
Derivative Liability	3	15
Gulf Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	5	1
Derivative asset, gross amount offset	(4)	0
Derivative Asset	1	1
Derivative liability, gross	29	100
Derivative liability, gross amounts offset	(4)	0
Derivative Liability	25	100
Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	7	0
Derivative asset, gross amount offset	(3)	0
Derivative Asset	4	0
Derivative liability, gross	11	47
Derivative liability, gross amounts offset	(3)	0
Derivative Liability	8	47
Southern Power [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	4	4
Derivative liability, gross	1	1
Southern Power [Member] | Energy-related derivatives | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	22	7
Derivative asset, gross amount offset	(5)	(1)
Derivative Asset	17	6
Derivative liability, gross	63	3
Derivative liability, gross amounts offset	(5)	(1)
Derivative Liability	58	2
Southern Power [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	3	1
Southern Power [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	1	1
Southern Power [Member] | Interest rate derivatives | Other current assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	1	3
Southern Power [Member] | Interest rate derivatives | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	0
Hedging Instruments for Regulatory Purposes [Member] | Parent Company [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	98	3
Derivative liability, gross	60	217
Hedging Instruments for Regulatory Purposes [Member] | Parent Company [Member] | Energy-related derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	73	3
Hedging Instruments for Regulatory Purposes [Member] | Parent Company [Member] | Energy-related derivatives | Liabilities from risk management activities, net of collateral [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	27	130
Hedging Instruments for Regulatory Purposes [Member] | Parent Company [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	25	0
Hedging Instruments for Regulatory Purposes [Member] | Parent Company [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	33	87
Hedging Instruments for Regulatory Purposes [Member] | Parent Company [Member] | Interest rate derivatives | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	0
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	20	1
Derivative liability, gross	9	55
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy-related derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	13	1
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	7	0
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy-related derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	5	40
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	4	15
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	44	2
Derivative liability, gross	8	15
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	30	2
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	14	0
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	1	12
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	7	3
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	5	0
Derivative liability, gross	29	100
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	4	0
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	12	49
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	1	0
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	17	51
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Interest rate derivatives | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	1
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Interest rate derivatives | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	4	0
Derivative liability, gross	11	47
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	2	0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	2	0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	6	29
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	5	18
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	36	22
Derivative liability, gross	94	32
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Energy-related derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	23	3
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Energy-related derivatives | Liabilities from risk management activities, net of collateral [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	7	2
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Foreign currency derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Foreign currency derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Foreign currency derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	25	0
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Foreign currency derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	33	0
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Interest rate derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	12	19
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Interest rate derivatives | Liabilities from risk management activities, net of collateral [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	1	23
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Interest rate derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	1	0
Cash Flow and Fair Value Hedging [Member] | Parent Company [Member] | Interest rate derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	28	7
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest rate derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest rate derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	15
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	2	5
Derivative liability, gross	3	6
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest rate derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	2	5
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest rate derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest rate derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest rate derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	3	6
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	3	0
Derivative liability, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest rate derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	2	0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest rate derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	1	0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest rate derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest rate derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	18	3
Derivative liability, gross	62	2
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Energy-related derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	18	3
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Energy-related derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	4	2
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Foreign currency derivatives | Other current assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Foreign currency derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0	0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Foreign currency derivatives | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	25	0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Foreign currency derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	33	0
Successor [Member] | Southern Company Gas [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	581
Derivative asset, gross amount offset	(435)
Derivative Asset	146
Derivative liability, gross	569
Derivative liability, gross amounts offset	(497)
Derivative Liability	72
Collateral already posted, aggregate fair value	62	96
Successor [Member] | Southern Company Gas [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	552
Derivative liability, gross	563
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Fair value of energy-related derivatives and interest rate derivatives
Collateral already posted, aggregate fair value	8
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	482
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	66
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Assets From Risk Management Activities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	486
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	81
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	25
Derivative liability, gross	3
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Liabilities from risk management activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	3
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	1
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Assets From Risk Management Activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	24
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	4
Derivative liability, gross	3
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Liabilities from risk management activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	3
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	0
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Assets From Risk Management Activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	4
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Interest rate derivatives | Liabilities from risk management activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross	0
Successor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Interest rate derivatives | Assets From Risk Management Activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross	$ 0
Predecessor [Member] | Southern Company Gas [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		942
Derivative asset, gross amount offset		(724)
Derivative Asset		218
Derivative liability, gross		866
Derivative liability, gross amounts offset		(820)
Derivative Liability		46
Predecessor [Member] | Southern Company Gas [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		920
Derivative liability, gross		829
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Fair value of energy-related derivatives and interest rate derivatives
Collateral already posted, aggregate fair value		19
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		644
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		179
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Assets From Risk Management Activities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		741
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		185
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		10
Derivative liability, gross		30
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Liabilities from risk management activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		28
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		0
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Assets From Risk Management Activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		10
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		2
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		12
Derivative liability, gross		7
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Liabilities from risk management activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		5
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred charges and assets [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		0
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Assets From Risk Management Activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		3
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		2
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Interest rate derivatives | Liabilities from risk management activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative liability, gross		0
Predecessor [Member] | Cash Flow and Fair Value Hedging [Member] | Southern Company Gas [Member] | Interest rate derivatives | Assets From Risk Management Activities [Member] | Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Derivative asset, gross		$ 9

Derivatives - Pre-Tax Effects o

Derivatives - Pre-Tax Effects of Unrealized Derivative Gains (Losses) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	$ (35)	$ (217)
Regulatory Hedge Unrealized Gain	68	3
Collateral already posted, aggregate fair value	62
Energy-related derivatives
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	8
Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(16)	(130)
Energy-related derivatives | Other regulatory liabilities current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	56	3
Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(19)	(87)
Energy-related derivatives | Other regulatory liabilities deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	12	0
Alabama Power [Member] | Other Regulatory Assets [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(1)	(55)
Alabama Power [Member] | Other Regulatory Liabilities [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	12	1
Alabama Power [Member] | Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(1)	(40)
Alabama Power [Member] | Energy-related derivatives | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	8	1
Alabama Power [Member] | Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	0	(15)
Alabama Power [Member] | Energy-related derivatives | Other regulatory liabilities deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	4	0
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	0	(12)
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other regulatory liabilities current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	29	2
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	0	(3)
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	7	0
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other Regulatory Assets [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	0	(15)
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives | Other Regulatory Liabilities [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	36	2
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(25)	(100)
Regulatory Hedge Unrealized Gain	1	0
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(9)	(49)
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other regulatory liabilities current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	1	0
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(16)	(51)
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives | Other regulatory liabilities deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	0	0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(8)	(47)
Regulatory Hedge Unrealized Gain	1	0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(5)	(29)
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other regulatory liabilities current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	1	0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(3)	(18)
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives | Other regulatory liabilities deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	0	0
Successor [Member] | Southern Company Gas [Member]
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	62	96
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	8
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(1)
Regulatory Hedge Unrealized Gain	18
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(1)
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory liabilities current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	17
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	0
Successor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory liabilities deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	1
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value		$ 19
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(17)
Regulatory Hedge Unrealized Gain	15
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory assets current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(15)
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory liabilities current [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	15
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory assets deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Loss	(2)
Predecessor [Member] | Hedging Instruments for Regulatory Purposes [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other regulatory liabilities deferred [Member]
Derivatives, Fair Value [Line Items]
Regulatory Hedge Unrealized Gain	$ 0

Derivatives - Pre-Tax Effect120

Derivatives - Pre-Tax Effects of Derivatives Designated as Cash Flow Hedging (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			$ (220)	$ (22)	$ (16)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(112)	(9)	(8)
Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			18	0	0
Energy-related derivatives | Depreciation and Amortization [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			2	0	0
Energy-related derivatives | Cost of Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)	0	0
Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			(180)	(22)	(16)
Interest rate derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(18)	(9)	(8)
Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			(58)	0	0
Foreign currency derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(13)	0	0
Foreign currency derivatives | Other Nonoperating Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(82)	0	0
Alabama Power [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(6)	(3)	(3)
Alabama Power [Member] | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			(3)	(7)	(8)
Georgia Power [Member] | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			0	(15)	(8)
Georgia Power [Member] | Interest rate derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(4)	(3)	(3)
Gulf Power [Member] | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			0	1	0
Gulf Power [Member] | Interest rate derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)	(1)	(1)
Southern Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			(44)	0	0
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(94)	(1)	(1)
Southern Power [Member] | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			14	0	0
Southern Power [Member] | Energy-related derivatives | Amortization [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			2	0	0
Southern Power [Member] | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			0	0	0
Southern Power [Member] | Interest rate derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)	(1)	(1)
Southern Power [Member] | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			(58)	0	0
Southern Power [Member] | Foreign currency derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(13)	0	0
Southern Power [Member] | Foreign currency derivatives | Other Nonoperating Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			$ (82)	0	0
Predecessor [Member] | Southern Company Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)		$ (64)		3	(8)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		(1)		(9)	5
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)		0		3	(8)
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Cost of Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		(1)		(10)	4
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Other Operations And Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				(1)	1
Predecessor [Member] | Southern Company Gas [Member] | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)		(64)		0	0
Predecessor [Member] | Southern Company Gas [Member] | Interest rate derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		$ 0		$ 2	$ 0
Successor [Member] | Southern Company Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	$ (3)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	2
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Cost of Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)
Successor [Member] | Southern Company Gas [Member] | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(5)
Successor [Member] | Southern Company Gas [Member] | Interest rate derivatives | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ 0

Derivatives - Pre-Tax Effect121

Derivatives - Pre-Tax Effects of Derivatives Designated as Fair Value Hedging (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Parent Company [Member] | Interest rate derivatives | Interest Expense [Member] | Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Fair Value Hedges Recognized in Earnings	$ (21)	$ 2	$ (3)

Derivatives - Pre-Tax Effect122

Derivatives - Pre-Tax Effects of Derivatives Not Designated as Hedging (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Energy-related derivatives | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			$ 38	$ (2)	$ 2
Energy-related derivatives | Wholesale Electric Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			2	(5)	6
Energy-related derivatives | Fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			0	3	(4)
Energy-related derivatives | Natural Gas Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			33	0	0
Energy-related derivatives | Cost of Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			$ 3	0	0
Successor [Member] | Southern Company Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 3
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	36
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Natural Gas Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	33
Successor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Cost of Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3
Successor [Member] | Southern Company Gas [Member] | Weather Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 6
Predecessor [Member] | Southern Company Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (162)		(22)	155
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		(63)		50	142
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Natural Gas Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		(1)		56	149
Predecessor [Member] | Southern Company Gas [Member] | Energy-related derivatives | Cost of Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		(62)		(6)	(7)
Predecessor [Member] | Southern Company Gas [Member] | Weather Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 3		$ 12	$ (7)

Derivatives - Textual (Details)

Derivatives - Textual (Details)	Jan. 23, 2015USD ($)	Sep. 30, 2016USD ($)	May 31, 2016USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)MMBTU	Dec. 31, 2016USD ($)MMBTU	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Nov. 30, 2015USD ($)
Derivative [Line Items]
Notional Amount					$ 4,027,000,000	$ 4,027,000,000
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU						9,000,000
Realized gain (loss) on termination of interest rate derivatives						$ (220,000,000)	$ (22,000,000)	$ (16,000,000)
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period					(21,000,000)	(21,000,000)
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months						17,000,000
Gulf Power [Member]
Derivative [Line Items]
Derivative collateral obligation to return cash					$ 0	$ 0
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					51,000,000	51,000,000
Longest Hedge Date						2,020
Mississippi Power [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					36,000,000	36,000,000
Longest Hedge Date						2,020
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period					$ (2,000,000)	$ (2,000,000)
Georgia Power [Member]
Derivative [Line Items]
Required Period For Options And Hedges						48 months	24 months
Notional Amount					950,000,000	$ 950,000,000
Derivative collateral obligation to return cash					0	$ 0
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU						3,000,000
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period					4,000,000	$ 4,000,000
Southern Company Gas [Member]
Derivative [Line Items]
Fair value of derivative liabilities with contingent features					5,000,000	5,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features					9,000,000	9,000,000
Alabama Power [Member]
Derivative [Line Items]
Derivative collateral obligation to return cash					0	$ 0
Longest Hedge Date						2,020
Estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period					(6,000,000)	$ (6,000,000)
Southern Power [Member]
Derivative [Line Items]
Derivative collateral obligation to return cash					0	$ 0
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU						3,000,000
Realized gain (loss) on termination of interest rate derivatives						$ (44,000,000)	$ 0	0
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months						14,000,000
Parent Company and Southern Power [Member]
Derivative [Line Items]
Foreign Currency Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months					$ (25,000,000)	(25,000,000)
Interest rate derivatives
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives						(180,000,000)	(22,000,000)	(16,000,000)
Interest rate derivatives | Gulf Power [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives						0	1,000,000	0
Interest rate derivatives | Georgia Power [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives						0	(15,000,000)	(8,000,000)
Interest rate derivatives | Alabama Power [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives						(3,000,000)	(7,000,000)	(8,000,000)
Interest rate derivatives | Southern Power [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives						$ 0	0	0
Interest Rate Swap [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Notional Amount	$ 800,000,000
Public Utilities, Inventory, Natural Gas [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					500,000,000	500,000,000
Public Utilities, Inventory, Natural Gas [Member] | Georgia Power [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					155,000,000	155,000,000
Longest Hedge Date						2,020
Public Utilities, Inventory, Natural Gas [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					157,000,000	157,000,000
Public Utilities, Inventory, Natural Gas [Member] | Alabama Power [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					74,000,000	74,000,000
Public Utilities, Inventory, Natural Gas [Member] | Southern Power [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					27,000,000	27,000,000
Longest Non-Hedge Date						2,017
Public Utilities, Inventory, Power Position [Member] | Southern Power [Member]
Derivative [Line Items]
Net volume of energy-related derivative contracts for natural gas positions | MMBTU					6,100,000	6,100,000
Public Utilities, Inventory, Fuel [Member]
Derivative [Line Items]
Longest Hedge Date						2,020
Longest Non-Hedge Date						2,022
Public Utilities, Inventory, Fuel [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Longest Non-Hedge Date						2,022
Minimum [Member] | Interest Rate Swap [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Term of contract	10 years
Maximum [Member] | Interest Rate Swap [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Term of contract	30 years
Cash Flow Hedging [Member] | Mississippi Power [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives						$ 3,000,000	$ 0	$ 0
Cash Flow Hedging [Member] | Interest rate derivatives | Georgia Power [Member]
Derivative [Line Items]
Notional Amount					$ 0	$ 0
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Derivative, Settlement, Notional Amount		$ 200,000,000	$ 400,000,000	$ 200,000,000					$ 200,000,000
Derivative Instruments, Loss Recognized in Other Comprehensive Income (Loss), Effective Portion		$ 35,000,000	$ 26,000,000
Successor [Member] | Southern Company Gas [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives					(3,000,000)
Successor [Member] | Interest rate derivatives | Southern Company Gas [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives					$ (5,000,000)
Successor [Member] | Cash Flow Hedging [Member] | Interest rate derivatives | Southern Company Gas [Member]
Derivative [Line Items]
Realized gain (loss) on termination of interest rate derivatives				$ (5,000,000)

Acquisitions - Acquisitions Tab

Acquisitions - Acquisitions Table (Details) $ in Millions

Jan. 06, 2017MW

Dec. 21, 2016MW

Dec. 01, 2016MW

Nov. 16, 2016MW

Oct. 26, 2016MW

Aug. 26, 2016MW

Jul. 01, 2016MW

Jun. 30, 2016USD ($)MW

Apr. 07, 2016MW

Mar. 04, 2016MW

Feb. 11, 2016MW

Dec. 11, 2015MW

Nov. 23, 2015MW

Oct. 22, 2015MW

Aug. 31, 2015MW

Aug. 28, 2015MW

Apr. 30, 2015MW

Apr. 15, 2015MW

Nov. 30, 2016MW

Jul. 31, 2016MW

Dec. 31, 2016USD ($)MW

Jul. 31, 2016MW

Dec. 31, 2016USD ($)MW

Dec. 31, 2015USD ($)

Mar. 29, 2016

Dec. 17, 2015MW

Dec. 31, 2014USD ($)

Purchase Price Allocation

Goodwill

$ 6,251

$ 6,251

$ 2

Acquisition Information, by Acquisition [Abstract]

Assets

109,697

109,697

78,318

$ 70,233

PowerSecure International, Inc. [Member]

Purchase Price Allocation

Current assets

172

172

Property, plant, and equipment

46

46

Goodwill

101

101

Intangible assets

282

282

Other assets

4

4

Current liabilities

(114)

(114)

Long-term debt, including current portion

48

48

Other liabilities

(14)

(14)

Total purchase price

429

429

Southern Power [Member]

Business Acquisition [Line Items]

Business Combination, Contingent Consideration, Liability

46

46

36

Purchase Price Allocation

Total purchase price

2,603

2,603

$ 1,931

Acquisition Information, by Acquisition [Abstract]

Life Output Of Plant

20 years

Assets

15,169

$ 15,169

$ 8,905

Southern Power [Member] | Boulder 1 [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

100

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Life Output Of Plant

20 years

Southern Power [Member] | 70SM1 8ME, LCC (Calipatria) [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

20

Noncontrolling Interest, Ownership Percentage by Parent

90.00%

Life Output Of Plant

20 years

Southern Power [Member] | East Pecos [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

120

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

15 years

Southern Power [Member] | Grant Plains [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

147

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

12 years

Southern Power [Member] | Grant Wind, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

151

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

20 years

Southern Power [Member] | Henrietta [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

102

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Life Output Of Plant

20 years

Southern Power [Member] | Lamesa [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

102

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

15 years

Southern Power [Member] | Mankato [Member]

Acquisition Information, by Acquisition [Abstract]

Capacity of Natural Gas Facility | MW

375

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

10 years

10 years

Southern Power [Member] | Passadumkeag, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

42

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

15 years

Southern Power [Member] | Rutherford [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

74

Noncontrolling Interest, Ownership Percentage by Parent

90.00%

Life Output Of Plant

15 years

Southern Power [Member] | Salt Fork [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

174

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Southern Power [Member] | Tyler Bluff [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

125

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

12 years

Southern Power [Member] | Wake Wind [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

257

Noncontrolling Interest, Ownership Percentage by Parent

90.10%

Life Output Of Plant

12 years

Southern Power [Member] | Series of Business Acquisitions [Member]

Business Acquisition [Line Items]

Business Combination, Contingent Consideration, Liability

281

$ 281

195

Purchase Price Allocation

CWIP

2,354

2,354

1,367

Property, plant, and equipment

302

302

315

Intangible assets

128

128

274

Other assets

52

52

64

Accounts payable

(16)

(16)

(89)

Debt

(217)

(217)

Total purchase price

$ 2,345

$ 2,345

$ 1,440

Southern Power [Member] | Desert Stateline Holdings, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

299

299

299

299

299

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

15.00%

Life Output Of Plant

20 years

20 years

Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

205

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Southern Power [Member] | Kay Wind, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

299

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

20 years

Southern Power [Member] | Lost Hills Blackwell Holdings, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

33

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Life Output Of Plant

29 years

Southern Power [Member] | GASNA 31P, LLC (Morelos) [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

15

Noncontrolling Interest, Ownership Percentage by Parent

90.00%

Life Output Of Plant

20 years

Southern Power [Member] | NS Solar Holdings, LLC (North Star) [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

61

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Life Output Of Plant

20 years

Southern Power [Member] | RE Roserock Holdings, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

160

160

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Life Output Of Plant

20 years

20 years

Southern Power [Member] | RE Tranquility Holdings, LLC [Member]

Acquisition Information, by Acquisition [Abstract]

Power of Solar Polycrystalline Silicon Facility | MW

205

205

205

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Life Output Of Plant

18 years

18 years

Turner Renewable Energy [Member] | 70SM1 8ME, LCC (Calipatria) [Member]

Acquisition Information, by Acquisition [Abstract]

Noncontrolling Interest, Ownership Percentage by Parent

10.00%

Turner Renewable Energy [Member] | Rutherford [Member]

Acquisition Information, by Acquisition [Abstract]

Noncontrolling Interest, Ownership Percentage by Parent

10.00%

Turner Renewable Energy [Member] | GASNA 31P, LLC (Morelos) [Member]

Acquisition Information, by Acquisition [Abstract]

Noncontrolling Interest, Ownership Percentage by Parent

10.00%

10.00%

Noncontrolling Interests [Member] | Series of Business Acquisitions [Member]

Business Acquisition [Line Items]

Business Combination, Contingent Consideration, Liability

$ 142

$ 142

$ 76

Purchase Price Allocation

Total purchase price

258

258

$ 491

Successor [Member] | Southern Company Gas [Member]

Purchase Price Allocation

Current assets

1,557

1,557

Property, plant, and equipment

10,108

10,108

Goodwill

5,967

5,967

Intangible assets

400

400

Regulatory assets

1,118

1,118

Other assets

229

229

Current liabilities

(2,201)

(2,201)

Other liabilities

(4,742)

(4,742)

Long-term debt

(4,261)

(4,261)

Noncontrolling interests

(174)

(174)

Total purchase price

8,001

8,001

Predecessor [Member] | Southern Company Gas [Member]

Purchase Price Allocation

Current assets

$ 1,474

Property, plant, and equipment

10,148

Goodwill

1,813

Intangible assets

101

Regulatory assets

679

Other assets

273

Current liabilities

(2,205)

Other liabilities

(4,600)

Long-term debt

(3,709)

Noncontrolling interests

(41)

Total purchase price

$ 3,933

Change in Basis

Current assets

83

Property, plant, and equipment

(40)

Goodwill

4,154

Other intangible assets

299

Regulatory assets

439

Other assets

(44)

Current liabilities

4

Other liabilities

(142)

Long-term debt

(552)

Contingently redeemable noncontrolling interest

(133)

Total purchase price/equity

4,068

Subsequent Event [Member] | Southern Power [Member] | Bethel [Member]

Acquisition Information, by Acquisition [Abstract]

Energy From Wind-Powered Generating Facilities | MW

276

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Life Output Of Plant

12 years

Grant County [Member] | Southern Power [Member] | Grant Plains [Member]

Acquisition Information, by Acquisition [Abstract]

Life Output Of Plant

20 years

Donley County [Member] | Southern Power [Member] | Salt Fork [Member]

Acquisition Information, by Acquisition [Abstract]

Life Output Of Plant

14 years

Gray County [Member] | Southern Power [Member] | Salt Fork [Member]

Acquisition Information, by Acquisition [Abstract]

Life Output Of Plant

12 years

Payables [Member] | Southern Power [Member] | Series of Business Acquisitions [Member]

Business Acquisition [Line Items]

Business Combination, Contingent Consideration, Liability

67

67

Senior Lien [Member] | Southern Power [Member]

Acquisition Information, by Acquisition [Abstract]

Assets

$ 408

$ 408

Acquisitions - Pro Forma Consol

Acquisitions - Pro Forma Consolidated Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Mankato [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue	$ 40	$ 39
Business Acquisition, Pro Forma Net Income (Loss)	14	11
Southern Company Gas [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue	21,791	21,430
Business Acquisition, Pro Forma Net Income (Loss)	$ 2,591	$ 2,665
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 2.70	$ 2.85
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 2.68	$ 2.84

Acquisitions - Construction Pro

Acquisitions - Construction Projects (Details) - MW

Jul. 01, 2016

Mar. 04, 2016

Dec. 17, 2015

Nov. 23, 2015

Aug. 31, 2015

Aug. 28, 2015

Dec. 31, 2016

Nov. 30, 2016

Oct. 31, 2016

Aug. 31, 2016

Jul. 31, 2016

Mar. 31, 2016

Feb. 29, 2016

Jul. 31, 2016

Dec. 31, 2016

Dec. 31, 2015

Mar. 29, 2016

Southern Power [Member]

Business Acquisition [Line Items]

Life Output Of Plant

20 years

Southern Power [Member] | East Pecos [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

120

Life Output Of Plant

15 years

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Southern Power [Member] | Butler Solar LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

103

103

Life Output Of Plant

30 years

Southern Power [Member] | Butler Solar Farm, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

22

Life Output Of Plant

20 years

Southern Power [Member] | Desert Stateline Holdings, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

299

299

299

299

299

Life Output Of Plant

20 years

20 years

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

15.00%

Southern Power [Member] | RE Garland Holdings, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

185

Life Output Of Plant

20 years

15 years

Southern Power [Member] | RE Garland A Holdings, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

20

Life Output Of Plant

15 years

20 years

Southern Power [Member] | LS Pawpaw, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

30

Life Output Of Plant

30 years

Southern Power [Member] | RE Roserock Holdings, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

160

160

Life Output Of Plant

20 years

20 years

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Southern Power [Member] | Sandhills [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

146

Life Output Of Plant

25 years

Southern Power [Member] | RE Tranquility Holdings, LLC [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

205

205

205

Life Output Of Plant

18 years

18 years

Noncontrolling Interest, Ownership Percentage by Parent

51.00%

Southern Power [Member] | Lamesa [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

102

Life Output Of Plant

15 years

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Southern Power [Member] | Mankato Expansion [Member]

Business Acquisition [Line Items]

Capacity of Natural Gas Facility

345

345

Life Output Of Plant

20 years

Southern Power [Member] | Rutherford [Member]

Business Acquisition [Line Items]

Power of Solar Polycrystalline Silicon Facility

74

Life Output Of Plant

15 years

Noncontrolling Interest, Ownership Percentage by Parent

90.00%

Turner Renewable Energy [Member] | Rutherford [Member]

Business Acquisition [Line Items]

Noncontrolling Interest, Ownership Percentage by Parent

10.00%

Acquisitions - Textual (Details

Acquisitions - Textual (Details) $ / shares in Units, mi in Thousands, $ in Millions	Oct. 26, 2016MW	Sep. 01, 2016USD ($)mi	Aug. 26, 2016MW	Jul. 01, 2016USD ($)$ / sharesMWshares	May 09, 2016USD ($)$ / shares	Feb. 11, 2016MW	Oct. 22, 2015MW	Aug. 31, 2015MW	Dec. 31, 2016USD ($)$ / sharesMWshares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / sharesMWshares	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)$ / sharesMWshares	Jun. 30, 2016USD ($)	Jul. 31, 2016MW	Dec. 31, 2016USD ($)$ / sharesMWshares	Dec. 31, 2015USD ($)$ / sharesMWshares	Dec. 31, 2014USD ($)	Dec. 31, 2020Facility	Oct. 24, 2016MW	Oct. 03, 2016USD ($)	Oct. 02, 2016	Mar. 29, 2016	Feb. 12, 2016USD ($)
Business Acquisition [Line Items]
Goodwill									$ 6,251				$ 2				$ 6,251			$ 6,251	$ 2
Revenues									5,181	$ 6,264	$ 4,459	$ 3,992	3,568	$ 5,401	$ 4,337	$ 4,183				19,896	17,489	$ 18,467
Net income									197	1,139	623	489	271	959	629	508				2,448	2,367	1,963
Capacity Of Fuel Cell Systems | MW																								50
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months									108								108			108
Acquisitions Payable									$ 489				$ 0				$ 489			489	0
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders																				$ 618	$ 567	221
Common Stock, Shares Authorized | shares									1,500,000,000				1,500,000,000				1,500,000,000			1,500,000,000	1,500,000,000
Common stock, par value per share (in dollars per share) | $ / shares									$ 5				$ 5				$ 5			$ 5	$ 5
Construction in Progress, Gross									$ 8,977				$ 9,082				$ 8,977			$ 8,977	$ 9,082
PowerSecure International, Inc. [Member]
Business Acquisition [Line Items]
Intangible assets									282								282			282
Goodwill									101								101			101
Business acquisition share price (in dollars per share) | $ / shares					$ 18.75
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable					$ 429
Current liabilities									114								114			114
Southern Company Gas [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 8,000
Common Stock, Shares Authorized | shares				100,000,000
Preferred Stock, Shares Authorized | shares				10,000,000
Common stock, par value per share (in dollars per share) | $ / shares				$ 0.01
Southern Power [Member]
Business Acquisition [Line Items]
Total Cost Of Construction																				3,200
Payments to Acquire Businesses, Gross																				$ 2,300	1,400
Finite-Lived Intangible Asset, Useful Life																				19 years
Revenues									389	500	373	315	304	401	337	348				$ 1,577	$ 1,390	1,501
Net income									23	176	89	50	34	102	46	33
Life Output Of Plant																					20 years
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months									25								25			25
Acquisitions Payable									461				0				461			461	$ 0
Business Combination, Contingent Consideration, Liability									$ 46				$ 36				$ 46			46	36
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders																				$ 618	$ 567	221
Common Stock, Shares Authorized | shares									1,000,000				1,000,000				1,000,000			1,000,000	1,000,000
Common stock, par value per share (in dollars per share) | $ / shares									$ 0.01				$ 0.01				$ 0.01			$ 0.01	$ 0.01
Construction in Progress, Gross									$ 398				$ 1,137				$ 398			$ 398	$ 1,137
Capital Contributions from Parent Company																				$ 1,850	$ 646	147
Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Power of Solar Polycrystalline Silicon Facility | MW								299	299								299		299	299
Capacity Of Small Power Production Facility | MW													110								110
Noncontrolling Interest, Ownership Percentage by Parent								51.00%																			15.00%
Life Output Of Plant								20 years											20 years
Southern Power [Member] | Lost Hills Blackwell, North Star, Tranquillity, Desert Stateline, Roserock, Garland and Garland A [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders																					$ 227
Southern Power [Member] | 70SM1 8ME, LCC (Calipatria) [Member]
Business Acquisition [Line Items]
Power of Solar Polycrystalline Silicon Facility | MW						20
Noncontrolling Interest, Ownership Percentage by Parent						90.00%
Life Output Of Plant						20 years
Southern Power [Member] | Rutherford [Member]
Business Acquisition [Line Items]
Power of Solar Polycrystalline Silicon Facility | MW				74
Noncontrolling Interest, Ownership Percentage by Parent				90.00%
Life Output Of Plant				15 years
Southern Power [Member] | GASNA 31P, LLC (Morelos) [Member]
Business Acquisition [Line Items]
Power of Solar Polycrystalline Silicon Facility | MW							15
Noncontrolling Interest, Ownership Percentage by Parent							90.00%
Life Output Of Plant							20 years
Southern Power [Member] | Grant Plains [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent			100.00%
Life Output Of Plant			12 years
Energy From Wind-Powered Generating Facilities | MW			147
Southern Power [Member] | Mankato [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%
Life Output Of Plant	10 years																			10 years
Capacity of Natural Gas Facility | MW	375
Southern Power [Member] | Wake Wind [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	90.10%
Life Output Of Plant	12 years
Energy From Wind-Powered Generating Facilities | MW	257
Southern Power [Member] | Mankato Expansion [Member]
Business Acquisition [Line Items]
Life Output Of Plant																				20 years
Capacity of Natural Gas Facility | MW									345								345			345
Southern Power [Member] | Series of Business Acquisitions [Member]
Business Acquisition [Line Items]
Intangible assets									$ 128				$ 274				$ 128			$ 128	274
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months									9				14				9			9	14
Business Combination, Contingent Consideration, Liability									281				195				281			281	195
Construction in Progress, Gross									386								386			386
Southern Power [Member] | Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Revenues																				37
Noncontrolling Interests [Member] | Series of Business Acquisitions [Member]
Business Acquisition [Line Items]
Business Combination, Contingent Consideration, Liability									$ 142				$ 76				$ 142			$ 142	$ 76
Invenergy [Member] | Rutherford [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	9.90%
Turner Renewable Energy [Member] | 70SM1 8ME, LCC (Calipatria) [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent						10.00%
Turner Renewable Energy [Member] | Rutherford [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent				10.00%
Turner Renewable Energy [Member] | GASNA 31P, LLC (Morelos) [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent							10.00%						10.00%								10.00%
Turner Renewable Energy [Member] | 70SM1 8ME, LCC (Calipatria) and Rutherford [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent									10.00%								10.00%			10.00%
First Solar [Member] | Desert Stateline, Lost Hills Blackwell, and North Star [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent													49.00%								49.00%
Southern Company Gas [Member]
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months									$ 73								$ 73			$ 73
Southern Company Gas [Member] | Southern Company [Member]
Business Acquisition [Line Items]
Business acquisition share price (in dollars per share) | $ / shares				$ 66
Southern Company Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Shares, Authorized | shares				110,000,000
Southern Company Gas [Member] | Southern Natural Gas Company, LLC [Member]
Business Acquisition [Line Items]
Pipeline infrastructure | mi		7
SunPower AssetCo, LLC [Member] | Boulder 1 and Henrietta [Member] [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent									49.00%								49.00%			49.00%
Southern Power and Turner Renewable Energy [Member]
Business Acquisition [Line Items]
Current liabilities									$ 217								$ 217			$ 217
Southern Power, Turner Renewable Energy, SunPower, and Invenergy [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross																				$ 2,600
Recurrent Energy [Member] | Garland, Garland A, Roserock, and Tranquility [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent													49.00%								49.00%
Southern Power, Turner Renewable Energy, First Solar, and Recurrent [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross																					$ 1,900
Elizabethtown Gas [Member]
Business Acquisition [Line Items]
Business Combination, Regulatory Approval Requirements, Required Rate Credit Payments to Customers									$ 0.4	17.5
Elizabethtown Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Business Combination, Regulatory Approval Requirements, Base Rate Case Filing Period																				3 years
Elkton Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Business Combination, Regulatory Approval Requirements, Base Rate Case Filing Period																				2 years
Class A Membership Interest [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions									66.00%								66.00%			66.00%
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%			100.00%
Percentage Of Entitled Cash Distributions									51.00%								51.00%			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%			100.00%
Class B Membership Interest [Member] | First Solar [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions									34.00%								34.00%			34.00%
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%			49.00%
Minimum [Member] | PowerSecure International, Inc. [Member]
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life																				1 year
Minimum [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life																				1 year
Minimum [Member] | Southern Power [Member] | Series of Business Acquisitions [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments									$ 530								$ 530			$ 530
Maximum [Member] | PowerSecure International, Inc. [Member]
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life																				26 years
Maximum [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life																				28 years
Maximum [Member] | Southern Power [Member] | Series of Business Acquisitions [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments									590								590			$ 590
Bridge Agreement [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																				111	41
Successor [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Intangible assets									400								400			400
Goodwill									5,967								5,967			5,967
Current liabilities									2,201								2,201			2,201
Successor [Member] | Elizabethtown Gas and Elkton Gas [Member]
Business Acquisition [Line Items]
Business Combination, Regulatory Approval Requirements, Required Rate Credit Payments to Customers																	18
Successor [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Goodwill									30
Merger-related expenses																	41
Goodwill									5,967								5,967			$ 5,967
Revenues									1,109	543							1,652
Net income									$ 110	$ 4							$ 114
Common Stock, Shares Authorized | shares									100,000,000								100,000,000			100,000,000
Common stock, par value per share (in dollars per share) | $ / shares									$ 0.01								$ 0.01			$ 0.01
Construction in Progress, Gross									$ 496								$ 496			$ 496
Capital Contributions from Parent Company																	1,085
Successor [Member] | Southern Company Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Business Combination, Integration Related Costs																	20
Goodwill									$ 6,000								6,000			6,000
Business Combination, Provisional Information, Pushdown Accounting, Adjustment, Income (Loss) before Income Taxes, Extraordinary Items, Noncontrolling Interest																	(20)
Business Combination, Provisional Information, Pushdown Accounting, Adjustment, Revenue																	(17)
Business Combination, Provisional Information, Pushdown Accounting, Adjustment, Amortization Expense																	22
Business Combination, Provisional Information, Pushdown Accounting, Adjustment, Interest Expense																	(19)
Predecessor [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Goodwill																	4,154
Intangible assets											101							$ 101
Goodwill											1,813							1,813
Current liabilities											2,205							2,205
Predecessor [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																		56			44	0
Goodwill													$ 1,813								1,813
Revenues											571	1,334	962	584	674	1,721		1,905			3,941	5,385
Net income											$ (51)	$ 182	$ 107	$ 11	$ 42	$ 193		131			$ 353	482
Common Stock, Shares Authorized | shares													750,000,000								750,000,000
Common stock, par value per share (in dollars per share) | $ / shares													$ 5								$ 5
Construction in Progress, Gross													$ 414								$ 414
Predecessor [Member] | Southern Company Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																		56			44
Business Combination, Integration Related Costs																		25
Merger-Related Expenses [Member] | Successor [Member] | Southern Company Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																	$ 3
Merger-Related Expenses [Member] | Predecessor [Member] | Southern Company Gas [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																		$ 31
Operating Expense [Member] | Bridge Agreement [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																				80	27
Other Income Expense Net [Member] | Bridge Agreement [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Merger-related expenses																				$ 31	14
SNG [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Capital Contributions from Parent Company		$ 1,050
Proceeds from Contributions from Affiliates		360
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 700
Southstar [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent																										85.00%
Southern Natural Gas Company, LLC [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Ownership percentage, equity method investment		50.00%
Equity Method Investment, Aggregate Cost		$ 1,400
Southstar [Member] | Piedmont [Member]
Business Acquisition [Line Items]
Ownership percentage of noncontrolling interest																										15.00%
Southstar [Member] | Southern Company Gas [Member]
Business Acquisition [Line Items]
Ownership percentage of noncontrolling interest																										85.00%
Agreement to purchase remaining interest																									$ 160			$ 160
Allianz Risk Transfer (Bermuda) Ltd. [Member] | Southern Power [Member] | Grant Plains [Member]
Business Acquisition [Line Items]
Life Output Of Plant			10 years
Renewable Energy Systems Americas, Inc. [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Energy From Wind-Powered Generating Facilities | MW									3,000								3,000			3,000
Wind Generating Facility [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Project Qualification for Production Tax Credits, Percentage																				100.00%
Wind Generating Facility [Member] | Scenario, Forecast [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Number of Projects to be Placed In Service | Facility																							10
Grant County [Member] | Southern Power [Member] | Grant Plains [Member]
Business Acquisition [Line Items]
Life Output Of Plant			20 years
Intangible Assets 1 [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Life Output Of Plant																				10 years
Intangible Assets 2 [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Life Output Of Plant																				20 years
Noncontrolling Interest [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders																				$ 618	567	221
Noncontrolling Interest [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders																				618	$ 567	$ 221
Noncontrolling Interest [Member] | Southern Power [Member] | Series of Business Acquisitions [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders																				$ 51

Segment and Related Informat128

Segment and Related Information - Financial Data for Business Segments and Products and Services (Details) - USD ($) $ in Millions	3 Months Ended								6 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Jun. 30, 2016	Oct. 03, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Financial data for business segments
Operating revenues	$ 5,181	$ 6,264	$ 4,459	$ 3,992	$ 3,568	$ 5,401	$ 4,337	$ 4,183				$ 19,896	$ 17,489	$ 18,467
Depreciation and amortization												2,502	2,034	1,945
Depreciation and amortization												2,923	2,395	2,293
Earnings from equity method investments											$ 15	59	0	0
Interest income												20	23	19
Interest expense												(1,317)	(840)	(835)
Income taxes												951	1,194	977
Segment net income (loss)	197	1,139	623	489	271	959	629	508				2,448	2,367	1,963
Gross property additions												7,624	6,169	6,522
Total assets	109,697				78,318				$ 109,697			109,697	78,318	70,233
Segment and Related Information (Textual) [Abstract]
Estimated loss on Kemper IGCC												428	365	868
Unamortized Debt Issuance Expense	213				241				213			213	241	202
Kemper IGCC [Member]
Segment and Related Information (Textual) [Abstract]
After Tax Charge To Income	127	54	50	33	113	93	14	6				264	226	536
Electric Utilities [Member]
Financial data for business segments
Operating revenues												17,941	17,442	18,406
Depreciation and amortization												2,233	2,020	1,929
Earnings from equity method investments												2	1	1
Interest income												13	22	18
Interest expense												(931)	(774)	(794)
Income taxes												1,091	1,326	1,053
Segment net income (loss)												2,571	2,401	1,969
Gross property additions												6,966	6,129	6,510
Total assets	86,994				77,560				86,994			86,994	77,560	69,402
Traditional Operating Companies | Electric Utilities [Member]
Financial data for business segments
Operating revenues												16,803	16,491	17,354
Depreciation and amortization												1,881	1,772	1,709
Earnings from equity method investments												2	1	1
Interest income												6	19	17
Interest expense												(814)	(697)	(705)
Income taxes												1,286	1,305	1,056
Segment net income (loss)												2,233	2,186	1,797
Gross property additions												4,852	5,124	5,568
Total assets	72,141				69,052				72,141			72,141	69,052	64,300
Southern Power [Member]
Financial data for business segments
Operating revenues												419	417	383
Southern Power [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues												1,577	1,390	1,501
Depreciation and amortization												352	248	220
Earnings from equity method investments												0	0	0
Interest income												7	2	1
Interest expense												(117)	(77)	(89)
Income taxes												(195)	21	(3)
Segment net income (loss)												338	215	172
Gross property additions												2,114	1,005	942
Total assets	15,169				8,905				15,169			15,169	8,905	5,233
Southern Company Gas [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues												1,652	0	0
Depreciation and amortization												238	0	0
Earnings from equity method investments												60	0	0
Interest income												2	0	0
Interest expense												(81)	0	0
Income taxes												76	0	0
Segment net income (loss)												114	0	0
Gross property additions												618	0	0
Total assets	21,853				0				21,853			21,853	0	0
All Other [Member]
Financial data for business segments
Operating revenues												463	152	159
Depreciation and amortization												31	14	16
Earnings from equity method investments												(3)	(1)	(1)
Interest income												20	6	3
Interest expense												(317)	(69)	(43)
Income taxes												(216)	(132)	(76)
Segment net income (loss)												(230)	(32)	(3)
Gross property additions												41	40	11
Total assets	2,474				1,819				2,474			2,474	1,819	1,143
Intersegment Eliminations [Member]
Financial data for business segments
Operating revenues												(160)	(105)	(98)
Depreciation and amortization												0	0	0
Earnings from equity method investments												0	0	0
Interest income												(15)	(5)	(2)
Interest expense												12	3	2
Income taxes												0	0	0
Segment net income (loss)												(7)	(2)	(3)
Gross property additions												(1)	0	1
Total assets	(1,624)				(1,061)				(1,624)			(1,624)	(1,061)	(312)
Intersegment Eliminations [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues												(439)	(439)	(449)
Depreciation and amortization												0	0	0
Earnings from equity method investments												0	0	0
Interest income												0	1	0
Interest expense												0	0	0
Income taxes												0	0	0
Segment net income (loss)												0	0	0
Gross property additions												0	0	0
Total assets	(316)				(397)				(316)			(316)	(397)	(131)
Deferred Tax Liability, Noncurrent [Member]
Segment and Related Information (Textual) [Abstract]
Prior period reclassification adjustment														488
Successor [Member] | Southern Company Gas [Member]
Financial data for business segments
Operating revenues	1,109	543							1,652
Depreciation and amortization									238
Earnings from equity method investments									60
EBIT	221	50
Interest expense									(81)
Income taxes									76
Segment net income (loss)	110	$ 4							114
Gross property additions									632
Total assets	21,853								21,853			21,853
Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member]
Financial data for business segments
Operating revenues									1,751
Depreciation and amortization									230
Earnings from equity method investments									58
Interest expense									(125)
Income taxes									71
Segment net income (loss)									116
Gross property additions									621
Total assets	24,875								24,875			24,875
Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Gas Distribution Operations [Member]
Financial data for business segments
Operating revenues									1,342
Depreciation and amortization									185
Earnings from equity method investments									0
Interest expense									(105)
Income taxes									51
Segment net income (loss)									77
Gross property additions									561
Total assets	19,453								19,453			19,453
Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Gas Marketing Services [Member]
Financial data for business segments
Operating revenues									354
Depreciation and amortization									35
Earnings from equity method investments									0
Interest expense									(1)
Income taxes									7
Segment net income (loss)									19
Gross property additions									5
Total assets	2,084								2,084			2,084
Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues									24
Cost of Revenue									6,116
Depreciation and amortization									1
Earnings from equity method investments									0
Interest expense									(3)
Income taxes									(3)
Segment net income (loss)									0
Gross property additions									1
Total assets	1,127								1,127			1,127
Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Gas Midstream Operations [Member]
Financial data for business segments
Operating revenues									31
Depreciation and amortization									9
Earnings from equity method investments									58
Interest expense									(16)
Income taxes									16
Segment net income (loss)									20
Gross property additions									54
Total assets	2,211								2,211			2,211
Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | All Other [Member]
Financial data for business segments
Operating revenues									3
Depreciation and amortization									8
Earnings from equity method investments									2
Interest expense									44
Income taxes									5
Segment net income (loss)									(2)
Gross property additions									11
Total assets	11,145								11,145			11,145
Successor [Member] | Southern Company Gas [Member] | Intersegment Eliminations [Member]
Financial data for business segments
Operating revenues									(102)
Depreciation and amortization									0
Earnings from equity method investments									0
Interest expense									0
Income taxes									0
Segment net income (loss)									0
Gross property additions									0
Total assets	$ (14,167)								(14,167)			$ (14,167)
Predecessor [Member] | Southern Company Gas [Member]
Financial data for business segments
Operating revenues			571	1,334	962	584	674	1,721		$ 1,905			3,941	5,385
Depreciation and amortization										206			397	380
Earnings from equity method investments										2			6	8
EBIT			(23)	351	221	62	111	367		328			761	1,112
Interest expense										(96)			(175)	(182)
Income taxes										87			213	350
Segment net income (loss)			$ (51)	$ 182	107	$ 11	$ 42	$ 193		131			353	482
Gross property additions										548			1,027	769
Total assets					14,754								14,754	14,862
Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member]
Financial data for business segments
Operating revenues										2,003			4,141	5,661
Depreciation and amortization										199			380	364
EBIT										388			820	1,122
Gross property additions										532			993	743
Total assets					14,832								14,832	14,804
Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Gas Distribution Operations [Member]
Financial data for business segments
Operating revenues										1,575			3,049	4,001
Depreciation and amortization										178			336	317
EBIT										353			581	582
Gross property additions										484			957	715
Total assets					12,519								12,519	12,038
Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Gas Marketing Services [Member]
Financial data for business segments
Operating revenues										435			835	994
Depreciation and amortization										11			25	28
EBIT										109			152	132
Gross property additions										4			7	11
Total assets					686								686	670
Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues										(32)			202	578
Cost of Revenue										2,675			6,492	10,849
Depreciation and amortization										1			1	1
EBIT										(68)			110	425
Gross property additions										1			2	2
Total assets					935								935	1,402
Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Gas Midstream Operations [Member]
Financial data for business segments
Operating revenues										25			55	88
Depreciation and amortization										9			18	18
EBIT										(6)			(23)	(17)
Gross property additions										43			27	15
Total assets					692								692	694
Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | All Other [Member]
Financial data for business segments
Operating revenues										4			11	7
Depreciation and amortization										7			17	16
EBIT										(60)			(59)	(10)
Gross property additions										16			34	26
Total assets					9,662								9,662	9,705
Predecessor [Member] | Southern Company Gas [Member] | Intersegment Eliminations [Member]
Financial data for business segments
Operating revenues										(102)			(211)	(283)
Depreciation and amortization										0			0	0
EBIT										0			0	0
Gross property additions										0			0	0
Total assets					$ (9,740)								(9,740)	(9,647)
Third Party Gross Revenues | Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues									5,807
Third Party Gross Revenues | Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues										2,500			6,286	10,709
Intercompany Revenues | Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues									333
Intercompany Revenues | Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues										143			408	718
Total Gross Revenues | Successor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues									$ 6,140
Total Gross Revenues | Predecessor [Member] | Southern Company Gas [Member] | Operating Segments [Member] | Wholesale Gas Services [Member]
Financial data for business segments
Operating revenues										$ 2,643			$ 6,694	$ 11,427

Segment and Related Informat129

Segment and Related Information - Electric Utilities' Revenues (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue from External Customer [Line Items]
Electric Utilities Revenues	$ 5,181	$ 6,264	$ 4,459	$ 3,992	$ 3,568	$ 5,401	$ 4,337	$ 4,183	$ 19,896	$ 17,489	$ 18,467
Retail [Member]
Revenue from External Customer [Line Items]
Electric Utilities Revenues									15,234	14,987	15,550
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Utilities Revenues									1,926	1,798	2,184
Other Electric Revenue [Member]
Revenue from External Customer [Line Items]
Electric Utilities Revenues									781	657	672
Electric Utilities [Member]
Revenue from External Customer [Line Items]
Electric Utilities Revenues									$ 17,941	$ 17,442	$ 18,406

Segment and Related Informat130

Segment and Related Information - Gas Revenues (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Segment Reporting Information [Line Items]
Gas Revenue	$ 1,652
Gas Distribution Operations [Member]
Segment Reporting Information [Line Items]
Gas Revenue	1,266
Gas Marketing Services [Member]
Segment Reporting Information [Line Items]
Gas Revenue	354
Other Gas Revenue [Member]
Segment Reporting Information [Line Items]
Gas Revenue	$ 32

Segment and Related Informat131

Segment and Related Information - Textuals (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)statesegment	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)statesegment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 01, 2016
Segment Reporting Information [Line Items]
Number of traditional operating companies | segment	4								4
Revenues | $	$ 5,181	$ 6,264	$ 4,459	$ 3,992	$ 3,568	$ 5,401	$ 4,337	$ 4,183	$ 19,896	$ 17,489	$ 18,467
Traditional Operating Companies
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4								4
Southern Company Gas [Member]
Segment Reporting Information [Line Items]
Number of reportable segments | segment									4
Number of states in which entity operates | state	7								7
Southern Natural Gas Company, LLC [Member] | Southern Company Gas [Member]
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment												50.00%
Southern Power [Member]
Segment Reporting Information [Line Items]
Revenues | $									$ 419	$ 417	$ 383

Discontinued Operations (Detail

Discontinued Operations (Details) - Predecessor [Member] - Southern Company Gas [Member] - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of business			$ 225
Discontinued operation tax effect	$ 29	$ 31	60
Repatriation of foreign earnings	$ 86
Goodwill impairment			19
Income taxes			0
Depreciation and monetary suspension			$ 7

Discontinued Operations - Comp

Discontinued Operations - Components of Discontinued Operations (Details) - Predecessor [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended	12 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Tropical Shipping [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues					$ 243
Cost of goods sold					149
Operation and maintenance					75
Depreciation and amortization					5
Taxes other than income taxes					5
Loss on sale and goodwill impairment					28
Total operating expenses					262
Operating (loss) income					(19)
(Loss) income before income taxes					(19)
Income tax expense					(61)
(Loss) income from discontinued operations, net of tax					(80)
Southern Company Gas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax expense	$ (29)	$ (31)			(60)
(Loss) income from discontinued operations, net of tax			$ 0	$ 0	(80)
Depreciation and monetary suspension					7
Goodwill impairment					$ 19

Noncontrolling Interest - Redee

Noncontrolling Interest - Redeemable Noncontrolling Interest (Details) - Southern Power [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Roll Forward]
Redeemable Put Option, Beginning balance	$ 43	$ 39	$ 29
Net income attributable to redeemable noncontrolling interest	4	2	4
Distributions to redeemable noncontrolling interest	(1)	0	(1)
Capital contributions from redeemable noncontrolling interest	118	2	7
Redeemable Put Option, Ending balance	$ 164	$ 43	$ 39

Noncontrolling Interest - Net I

Noncontrolling Interest - Net Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Consolidated Net Income	$ 2,529	$ 2,435	$ 2,031
Net income (loss) attributable to noncontrolling interests	32	12	(2)
Southern Power [Member]
Noncontrolling Interest [Line Items]
Consolidated Net Income	374	229	175
Net income (loss) attributable to noncontrolling interests	32	12	(2)
Net income attributable to redeemable noncontrolling interest	4	2	4
Net income attributable to Southern Power Company	338	215	172
Noncontrolling Interests [Member] | Southern Power [Member]
Noncontrolling Interest [Line Items]
Net income (loss) attributable to noncontrolling interests	$ 32	$ 12	$ (1)

Noncontrolling Interest - Textu

Noncontrolling Interest - Textuals (Details) - Southern Power [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Redeemable Noncontrolling Interest [Line Items]
Redeemable Put Option	$ 164	$ 43	$ 39	$ 29
Net income attributable to redeemable noncontrolling interest	4	$ 2	$ 4
Turner Renewable Energy [Member]
Redeemable Noncontrolling Interest [Line Items]
Redeemable Put Option	50
SunPower Corp. [Member]
Redeemable Noncontrolling Interest [Line Items]
Redeemable Put Option	$ 114

Capitalization (Details)

Capitalization (Details) - USD ($)	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total long -term senior notes and debt	$ 35,247,000,000		$ 20,418,000,000
2,017	2,019,000,000		1,995,000,000
2,018	2,353,000,000		1,697,000,000
2,019	3,076,000,000		1,176,000,000
2,021	2,655,000,000		200,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	21,797,000,000		$ 10,972,000,000
Annualized Interest Long Term Debt	$ 1,600,000,000
Common stock, par value per share (in dollars per share)	$ 5		$ 5
Common Stock, Shares Authorized	1,500,000,000		1,500,000,000
Treasury shares	800,000		3,400,000
Other Long-term Debt	$ 9,404,000,000		$ 6,808,000,000
Unamortized Fair Value Adjustment of Long-term Debt	578,000,000		0
Long Term Debt and Capital Lease Obligation Net	45,216,000,000		27,362,000,000
Long-term Debt and Capital Lease Obligations, Current	2,587,000,000		2,674,000,000
Long-term Debt and Capital Lease Obligations	$ 42,629,000,000		$ 24,688,000,000
Percent capitalization	61.30%		52.60%
Treasury Stock, Value	$ (31,000,000)		$ (142,000,000)
Additional Paid in Capital, Common Stock	9,661,000,000		6,282,000,000
Retained Earnings (Accumulated Deficit)	10,356,000,000		10,010,000,000
Accumulated OCI	(180,000,000)		(130,000,000)
Common Stockholders' Equity	$ 24,758,000,000		$ 20,592,000,000
Total common stockholders' equity - percent capitalization	35.60%		44.00%
Noncontrolling interests	$ 1,854,000,000		$ 1,390,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	26,612,000,000		21,982,000,000	$ 20,926,000,000	$ 19,764,000,000
Total Capitalization	$ 69,523,000,000		$ 46,831,000,000
Capitalization in Percent	100.00%		100.00%
Maturity of Long Term Senior Notes and Debt in Year Five [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.35%		2.35%
Maturity of Long Term Senior Notes and Debt in Year Five [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.10%		9.10%
Maturity Of First Mortgage Bonds Due Two Thousand Seventeen [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.30%		1.30%
Maturity Of First Mortgage Bonds Due Two Thousand Seventeen [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.20%		7.20%
Maturity of Long Term Senior Notes and Debt in Year Two [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.50%		1.50%
Maturity of Long Term Senior Notes and Debt in Year Two [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.40%		5.40%
Maturity of Long Term Senior Notes and Debt in Year Three [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.85%		1.85%
Maturity of Long Term Senior Notes and Debt in Year Three [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.55%		5.55%
Maturity Of Gas Facility Revenue Bonds Due 2022 to 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.28%
Maturity Of First Mortgage Bonds Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.70%
First Mortgage Bonds	$ 50,000,000		$ 0
Maturity Of First Mortgage Bonds Due Two Thousand Twenty Three To Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
First Mortgage Bonds	575,000,000		0
Maturity Of Gas Facility Revenue Bonds Due Two Thousand Twenty Two To Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Gas Facility Revenue Bonds	200,000,000		$ 0
Predecessor [Member]
Debt Instrument [Line Items]
Percent capitalization			45.20%
Total common stockholders' equity - percent capitalization			54.20%
Noncontrolling Interest in Percent of Capitalization			0.60%
Capitalization in Percent			100.00%
Southern Company Gas [Member]
Debt Instrument [Line Items]
2,017	22,000,000
2,018	155,000,000
2,019	350,000,000
2,021	330,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	3,900,000,000
First Mortgage Bonds	625,000,000		$ 375,000,000
Gas Facility Revenue Bonds	$ 200,000,000		$ 200,000,000
Southern Company Gas [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.50%
Southern Company Gas [Member] | Maturity of Long Term Senior Notes and Debt in Year Five [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.10%
Southern Company Gas [Member] | Maturity Of First Mortgage Bonds Due Two Thousand Seventeen [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Southern Company Gas [Member] | Maturity of Long Term Senior Notes and Debt in Year Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.50%
Southern Company Gas [Member] | Maturity of Long Term Senior Notes and Debt in Year Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Southern Company Gas [Member] | Notes Payable Due 2016-2046 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.47%		1.47%
Southern Company Gas [Member] | Notes Payable Due 2016-2046 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.10%		9.10%
Southern Company Gas [Member] | Maturity Of Senior Notes And Debt in Two Thousand Twenty Two to Two Thousand Forty Six [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.45%
Southern Company Gas [Member] | Maturity Of Senior Notes And Debt in Two Thousand Twenty Two to Two Thousand Forty Six [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.70%
Southern Company Gas [Member] | Maturity Of First Mortgage Bonds Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.70%
Southern Company Gas [Member] | Maturity Of First Mortgage Bonds Due Two Thousand Twenty Three To Two Thousand Thirty Eight [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.66%
Southern Company Gas [Member] | Maturity Of First Mortgage Bonds Due Two Thousand Twenty Three To Two Thousand Thirty Eight [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.58%
Southern Company Gas [Member] | Successor [Member]
Debt Instrument [Line Items]
2,017	$ 22,000,000
2,018	155,000,000
2,019	300,000,000
2,021	330,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	3,100,000,000
First Mortgage Bonds	625,000,000
Annualized Interest Long Term Debt	$ 207,000,000
Common stock, par value per share (in dollars per share)	$ 0.01
Common Stock, Shares Authorized	100,000,000
Common Stock, Shares, Outstanding	100
Treasury shares	0
Other Long-term Debt	$ 825,000,000
Unamortized Fair Value Adjustment of Long-term Debt	578,000,000
Debt Instrument, Unamortized Discount (Premium), Net	9,000,000
Long Term Debt and Capital Lease Obligation Net	5,281,000,000
Long-term Debt and Capital Lease Obligations, Current	22,000,000
Long-term Debt and Capital Lease Obligations	$ 5,259,000,000
Percent capitalization	36.60%
Treasury Stock, Value	$ 0
Additional Paid in Capital, Common Stock	9,095,000,000
Retained Earnings (Accumulated Deficit)	(12,000,000)
Accumulated OCI	26,000,000
Common Stockholders' Equity	$ 9,109,000,000
Total common stockholders' equity - percent capitalization	63.40%
Noncontrolling Interest in Percent of Capitalization	0.00%
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 9,109,000,000	$ 8,001,000,000
Total Capitalization	$ 14,368,000,000
Capitalization in Percent	100.00%
Southern Company Gas [Member] | Successor [Member] | Notes Payable Due 2016-2046 [Member]
Debt Instrument [Line Items]
Total long -term senior notes and debt	$ 3,887,000,000
Southern Company Gas [Member] | Successor [Member] | Maturity Of Gas Facility Revenue Bonds Due 2022 to 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.28%		1.28%
Southern Company Gas [Member] | Successor [Member] | Maturity Of First Mortgage Bonds Due 2019 [Member]
Debt Instrument [Line Items]
First Mortgage Bonds	$ 50,000,000
Southern Company Gas [Member] | Successor [Member] | Maturity Of First Mortgage Bonds Due Two Thousand Twenty Three To Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
First Mortgage Bonds	575,000,000
Southern Company Gas [Member] | Successor [Member] | Maturity Of Gas Facility Revenue Bonds Due Two Thousand Twenty Two To Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Gas Facility Revenue Bonds	200,000,000
Southern Company Gas [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Total long -term senior notes and debt			$ 3,181,000,000
First Mortgage Bonds			$ 375,000,000
Common stock, par value per share (in dollars per share)			$ 5
Common Stock, Shares Authorized			750,000,000
Common Stock, Shares, Outstanding			120,400,000
Treasury shares			200,000
Other Long-term Debt			$ 575,000,000
Unamortized Fair Value Adjustment of Long-term Debt			68,000,000
Debt Instrument, Unamortized Discount (Premium), Net			4,000,000
Long Term Debt and Capital Lease Obligation Net			3,820,000,000
Long-term Debt and Capital Lease Obligations, Current			545,000,000
Long-term Debt and Capital Lease Obligations			3,275,000,000
Treasury Stock, Value			(8,000,000)
Additional Paid in Capital, Common Stock			2,702,000,000
Retained Earnings (Accumulated Deficit)			1,421,000,000
Accumulated OCI			(186,000,000)
Common Stockholders' Equity			3,929,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 3,933,000,000	3,975,000,000	$ 3,828,000,000	$ 3,613,000,000
Total Capitalization			7,250,000,000
Southern Company Gas [Member] | Predecessor [Member] | Maturity Of Gas Facility Revenue Bonds Due Two Thousand Twenty Two To Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Gas Facility Revenue Bonds			200,000,000
Noncontrolling Interest [Member]
Debt Instrument [Line Items]
Noncontrolling interests	1,245,000,000		781,000,000
Noncontrolling Interest [Member] | Southern Company Gas [Member] | Successor [Member]
Debt Instrument [Line Items]
Noncontrolling interests	$ 0
Noncontrolling Interest [Member] | Southern Company Gas [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Noncontrolling interests			$ 46,000,000

Quarterly Financial Informat138

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								6 Months Ended		12 Months Ended			60 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Summarized quarterly financial information
Operating revenues	$ 5,181	$ 6,264	$ 4,459	$ 3,992	$ 3,568	$ 5,401	$ 4,337	$ 4,183			$ 19,896	$ 17,489	$ 18,467
Operating Income (Loss)	587	1,917	1,185	940	578	1,649	1,098	957			4,629	4,282	3,642
Net Income (Loss) After Dividends on Preferred and Preference Stock	$ 197	$ 1,139	$ 623	$ 489	$ 271	$ 959	$ 629	$ 508			$ 2,448	$ 2,367	$ 1,963
Basic EPS (in dollars per share)	$ 0.20	$ 1.18	$ 0.67	$ 0.53	$ 0.30	$ 1.05	$ 0.69	$ 0.56			$ 2.57	$ 2.60	$ 2.19
Diluted EPS (in dollars per share)	0.20	1.17	0.66	0.53	0.30	1.05	0.69	0.56			2.55	2.59	2.18
Cash dividends (in dollars per share)	0.5600	0.5600	0.5600	0.5425	0.5425	0.5425	0.5425	0.525			$ 2.2225	$ 2.1525	$ 2.0825
Trading Price Range, High, Per Common Share (in dollars per share)	52.23	54.64	53.64	51.73	47.5	46.84	45.44	53.16
Trading Price Range, Low, Per Common Share (in dollars per share)	$ 46.20	$ 50	$ 47.62	$ 46	$ 43.38	$ 41.81	$ 41.4	$ 43.55
Income tax expense (benefit)											$ 951	$ 1,194	$ 977
Georgia Power [Member]
Summarized quarterly financial information
Operating revenues	$ 1,762	$ 2,698	$ 2,051	$ 1,872	$ 1,641	$ 2,691	$ 2,016	$ 1,978			8,383	8,326	8,988
Operating Income (Loss)	258	1,054	656	509	376	964	554	454			2,477	2,348	2,296
Net Income (Loss) After Dividends on Preferred and Preference Stock	113	599	349	269	196	551	277	236			1,330	1,260	1,225
Income tax expense (benefit)											780	769	729
Alabama Power [Member]
Summarized quarterly financial information
Operating revenues	1,329	1,785	1,444	1,331	1,217	1,695	1,455	1,401			5,889	5,768	5,942
Operating Income (Loss)	252	650	430	333	264	555	398	346			1,665	1,563	1,525
Net Income (Loss) After Dividends on Preferred and Preference Stock	102	351	213	156	121	295	200	169			822	785	761
Income tax expense (benefit)											531	506	512
Gulf Power [Member]
Summarized quarterly financial information
Operating revenues	349	436	365	335	313	429	384	357			1,485	1,483	1,590
Operating Income (Loss)	54	90	74	65	58	91	69	72			283	290	281
Net Income (Loss) After Dividends on Preferred and Preference Stock	23	45	34	29	28	48	35	37			131	148	140
Income tax expense (benefit)											91	92	88
Mississippi Power [Member]
Summarized quarterly financial information
Operating revenues	277	352	277	257	246	341	275	276			1,163	1,138	1,243
Operating Income (Loss)	(166)	9	(28)	(10)	(143)	(66)	12	24			(195)	(173)	(689)
Net Income (Loss) After Dividends on Preferred and Preference Stock	(89)	26	2	11	(71)	(21)	49	35			(50)	(8)	(329)
Income tax expense (benefit)											(104)	(72)	(285)
Southern Power [Member]
Summarized quarterly financial information
Operating revenues	389	500	373	315	304	401	337	348			1,577	1,390	1,501
Operating Income (Loss)	28	134	81	47	55	129	75	67			290	326	255
Net Income (Loss) After Dividends on Preferred and Preference Stock	23	176	89	50	34	102	46	33
Income tax expense (benefit)											(195)	21	(3)
Kemper IGCC [Member]
Summarized quarterly financial information
Pre-Tax Charge To Income	206	88	81	53	183	150	23	9
After Tax Charge To Income	127	54	50	33	113	93	14	6			264	226	536
Kemper IGCC [Member] | Mississippi Power [Member]
Summarized quarterly financial information
Pre-Tax Charge To Income	206	88	81	53	183	150	23	9			348	365	868	$ 2,760
After Tax Charge To Income	127	54	50	33	113	93	14	6			215	226	536	$ 1,710
Restatement Adjustment
Summarized quarterly financial information
Income tax expense (benefit)		(9)	(11)	(5)
Restatement Adjustment | Georgia Power [Member]
Summarized quarterly financial information
Net Income (Loss) After Dividends on Preferred and Preference Stock							(47)
Predecessor [Member] | Southern Company Gas [Member]
Summarized quarterly financial information
Operating revenues			571	1,334	962	584	674	1,721		$ 1,905		3,941	5,385
Operating Income (Loss)			(27)	348	216	59	107	364		321		746	1,095
EBIT			(23)	351	221	62	111	367		328		761	1,112
Net Income (Loss) After Dividends on Preferred and Preference Stock			$ (51)	$ 182	$ 107	$ 11	$ 42	$ 193		131		353	482
Income tax expense (benefit)										$ 87		$ 213	$ 350
Successor [Member] | Southern Company Gas [Member]
Summarized quarterly financial information
Operating revenues	1,109	543							$ 1,652
Operating Income (Loss)	185	12							197
EBIT	221	50
Net Income (Loss) After Dividends on Preferred and Preference Stock	$ 110	$ 4							114
Income tax expense (benefit)									$ 76
Scenario, Previously Reported [Member]
Summarized quarterly financial information
Basic EPS (in dollars per share)		$ 1.17	$ 0.65	$ 0.53
Diluted EPS (in dollars per share)		$ 1.16	$ 0.65	$ 0.53
Accounting Standards Update 2016-09 | Georgia Power [Member]
Summarized quarterly financial information
Prior period reclassification adjustment		$ 1	$ 2	$ 1							$ 1
Accounting Standards Update 2016-09 | Alabama Power [Member]
Summarized quarterly financial information
Prior period reclassification adjustment		$ 2	$ 2	$ 1

Valuation and Qualifying Acc139

Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period			$ 13,341	$ 13,341	$ 18,253	$ 17,855
Additions Charged to Income				39,959	31,074	43,537
Additions Charged to Other Accounts				(1,257)	0	0
Valuation Acquisitions				40,629	0	0
Deductions				49,243	35,986	43,139
Balance at End of Period	$ 13,341	$ 43,429		43,429	13,341	18,253
Mississippi Power [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Retail Rate Recovery	342,000				371,000
Mississippi Power [Member] | Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period			287	287	825	3,018
Additions Charged to Income				1,295	(1,994)	562
Additions Charged to Other Accounts				0	0	0
Deductions				1,088	(1,456)	2,755
Balance at End of Period	287	494		494	287	825
Alabama Power [Member] | Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period			9,597	9,597	9,143	8,350
Additions Charged to Income				11,310	13,500	14,309
Additions Charged to Other Accounts				0	0	0
Deductions				10,420	13,046	13,516
Balance at End of Period	9,597	10,487		10,487	9,597	9,143
Georgia Power [Member] | Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period			2,147	2,147	6,076	5,074
Additions Charged to Income				14,476	16,862	24,141
Additions Charged to Other Accounts				0	0	0
Deductions				13,787	20,791	23,139
Balance at End of Period	2,147	2,836		2,836	2,147	6,076
Gulf Power [Member] | Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period			775	775	2,087	1,131
Additions Charged to Income				2,946	2,041	4,304
Additions Charged to Other Accounts				0	0	0
Deductions				2,989	3,353	3,348
Balance at End of Period	775	732		732	775	2,087
Successor [Member] | Southern Company Gas [Member] | Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period		37,663
Additions Charged to Income		9,500
Additions Charged to Other Accounts		(1,257)
Deductions		18,590
Balance at End of Period		27,316	37,663	27,316
Successor [Member] | Southern Company Gas [Member] | Income tax valuation
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period		19,182
Additions Charged to Income		0
Additions Charged to Other Accounts		0
Deductions		0
Balance at End of Period		19,182	19,182	19,182
Predecessor [Member] | Southern Company Gas [Member] | Provision for uncollectible accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period		37,663	29,142	29,142	35,069	29,261
Additions Charged to Income			15,976		27,050	54,790
Additions Charged to Other Accounts			1,608		3,017	1,414
Deductions			9,063		35,994	50,396
Balance at End of Period	29,142		37,663		29,142	35,069
Predecessor [Member] | Southern Company Gas [Member] | Income tax valuation
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of period		$ 19,182	19,182	$ 19,182	19,637	22,329
Additions Charged to Income			0		0	0
Additions Charged to Other Accounts			0		0	0
Deductions			0		455	2,692
Balance at End of Period	$ 19,182		$ 19,182		$ 19,182	$ 19,637

Uncategorized Items - so-201612

Label	Element	Value
Southern Company Gas [Member] | Successor [Member]
Stock or Unit Option Plan Expense	us-gaap_StockOptionPlanExpense	$ 20,000,000
Pension and Other Postretirement Benefit Expense	us-gaap_PensionAndOtherPostretirementBenefitExpense	6,000,000
Net Cash Provided by (Used in) Continuing Operations	us-gaap_NetCashProvidedByUsedInContinuingOperations	4,000,000
Proceeds from Issuance of Senior Long-term Debt	us-gaap_ProceedsFromIssuanceOfSeniorLongTermDebt	900,000,000
Goodwill, Impairment Loss	us-gaap_GoodwillImpairmentLoss	0
Payments to Acquire Equity Method Investments	us-gaap_PaymentsToAcquireEquityMethodInvestments	1,444,000,000
Net Cash Provided by (Used in) Discontinued Operations	us-gaap_NetCashProvidedByUsedInDiscontinuedOperations	0
Deferred Income Tax Expense (Benefit)	us-gaap_DeferredIncomeTaxExpenseBenefit	92,000,000
Pension and Other Postretirement Benefit Contributions	us-gaap_PensionAndOtherPostretirementBenefitContributions	125,000,000
Net Cash Provided by (Used in) Financing Activities	us-gaap_NetCashProvidedByUsedInFinancingActivities	2,399,000,000
Proceeds from Sales of Business, Affiliate and Productive Assets	us-gaap_ProceedsFromSalesOfBusinessAffiliateAndProductiveAssets	0
Payments for (Proceeds from) Other Investing Activities	us-gaap_PaymentsForProceedsFromOtherInvestingActivities	(9,000,000)
Cash Provided by (Used in) Investing Activities, Discontinued Operations	us-gaap_CashProvidedByUsedInInvestingActivitiesDiscontinuedOperations	0
Repayments of First Mortgage Bond	us-gaap_RepaymentsOfFirstMortgageBond	0
Repayments of Senior Debt	us-gaap_RepaymentsOfSeniorDebt	420,000,000
Increase (Decrease) in Accounts Payable	us-gaap_IncreaseDecreaseInAccountsPayable	194,000,000
Net Cash Provided by (Used in) Operating Activities	us-gaap_NetCashProvidedByUsedInOperatingActivities	(328,000,000)
Increase (Decrease) in Receivables	us-gaap_IncreaseDecreaseInReceivables	490,000,000
Payments to Acquire Property, Plant, and Equipment	us-gaap_PaymentsToAcquirePropertyPlantAndEquipment	614,000,000
Other Noncash Income (Expense)	us-gaap_OtherNoncashIncomeExpense	78,000,000
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	us-gaap_IncomeLossFromDiscontinuedOperationsNetOfTax	0
Change in Construction Payables	so_ChangeInConstructionPayables	22,000,000
Cash Provided by (Used in) Operating Activities, Discontinued Operations	us-gaap_CashProvidedByUsedInOperatingActivitiesDiscontinuedOperations	0
Increase (Decrease) in Energy Related Inventory, Natural Gas in Storage	so_IncreaseDecreaseinEnergyRelatedInventoryNaturalGasinStorage	226,000,000
Proceeds from (Payments for) Other Financing Activities	us-gaap_ProceedsFromPaymentsForOtherFinancingActivities	(8,000,000)
Increase (Decrease) in Other Current Liabilities	us-gaap_IncreaseDecreaseInOtherCurrentLiabilities	24,000,000
Increase Decrease in Accrued Taxes	so_IncreaseDecreaseInAccruedTaxes	8,000,000
Increase (Decrease) in Other Operating Assets	us-gaap_IncreaseDecreaseInOtherOperatingAssets	31,000,000
Hedge Settlements	so_HedgeSettlements	35,000,000
Proceeds from (Repayments of) Short-term Debt	us-gaap_ProceedsFromRepaymentsOfShortTermDebt	1,143,000,000
Increase (Decrease) in Accrued Salaries	us-gaap_IncreaseDecreaseInAccruedSalaries	(13,000,000)
Net Cash Provided by (Used in) Investing Activities	us-gaap_NetCashProvidedByUsedInInvestingActivities	(2,067,000,000)
Increase (Decrease) in Prepaid Taxes	us-gaap_IncreaseDecreaseInPrepaidTaxes	23,000,000
Payments for (Proceeds from) Removal Costs	us-gaap_PaymentsForProceedsFromRemovalCosts	40,000,000
Proceeds from (Payments to) Noncontrolling Interests	us-gaap_ProceedsFromPaymentsToMinorityShareholders	(160,000,000)
Payments of Ordinary Dividends, Common Stock	us-gaap_PaymentsOfDividendsCommonStock	126,000,000
Proceeds from Issuance of First Mortgage Bond	us-gaap_ProceedsFromIssuanceOfFirstMortgageBond	0
Southern Company Gas [Member] | Predecessor [Member]
Stock or Unit Option Plan Expense	us-gaap_StockOptionPlanExpense	20,000,000
Pension and Other Postretirement Benefit Expense	us-gaap_PensionAndOtherPostretirementBenefitExpense	5,000,000
Net Cash Provided by (Used in) Continuing Operations	us-gaap_NetCashProvidedByUsedInContinuingOperations	(4,000,000)
Proceeds from Contributions from Parent	us-gaap_ProceedsFromContributionsFromParent	0
Proceeds from Issuance of Senior Long-term Debt	us-gaap_ProceedsFromIssuanceOfSeniorLongTermDebt	350,000,000
Goodwill, Impairment Loss	us-gaap_GoodwillImpairmentLoss	0
Payments to Acquire Equity Method Investments	us-gaap_PaymentsToAcquireEquityMethodInvestments	14,000,000
Net Cash Provided by (Used in) Discontinued Operations	us-gaap_NetCashProvidedByUsedInDiscontinuedOperations	0
Deferred Income Tax Expense (Benefit)	us-gaap_DeferredIncomeTaxExpenseBenefit	8,000,000
Pension and Other Postretirement Benefit Contributions	us-gaap_PensionAndOtherPostretirementBenefitContributions	0
Net Cash Provided by (Used in) Financing Activities	us-gaap_NetCashProvidedByUsedInFinancingActivities	(558,000,000)
Proceeds from Sales of Business, Affiliate and Productive Assets	us-gaap_ProceedsFromSalesOfBusinessAffiliateAndProductiveAssets	0
Payments for (Proceeds from) Other Investing Activities	us-gaap_PaymentsForProceedsFromOtherInvestingActivities	(3,000,000)
Cash Provided by (Used in) Investing Activities, Discontinued Operations	us-gaap_CashProvidedByUsedInInvestingActivitiesDiscontinuedOperations	0
Repayments of First Mortgage Bond	us-gaap_RepaymentsOfFirstMortgageBond	125,000,000
Repayments of Senior Debt	us-gaap_RepaymentsOfSeniorDebt	0
Increase (Decrease) in Accounts Payable	us-gaap_IncreaseDecreaseInAccountsPayable	43,000,000
Net Cash Provided by (Used in) Operating Activities	us-gaap_NetCashProvidedByUsedInOperatingActivities	1,113,000,000
Increase (Decrease) in Receivables	us-gaap_IncreaseDecreaseInReceivables	(181,000,000)
Payments to Acquire Property, Plant, and Equipment	us-gaap_PaymentsToAcquirePropertyPlantAndEquipment	509,000,000
Other Noncash Income (Expense)	us-gaap_OtherNoncashIncomeExpense	82,000,000
Change in Construction Payables	so_ChangeInConstructionPayables	(7,000,000)
Cash Provided by (Used in) Operating Activities, Discontinued Operations	us-gaap_CashProvidedByUsedInOperatingActivitiesDiscontinuedOperations	0
Increase (Decrease) in Energy Related Inventory, Natural Gas in Storage	so_IncreaseDecreaseinEnergyRelatedInventoryNaturalGasinStorage	(273,000,000)
Proceeds from (Payments for) Other Financing Activities	us-gaap_ProceedsFromPaymentsForOtherFinancingActivities	10,000,000
Increase (Decrease) in Other Current Liabilities	us-gaap_IncreaseDecreaseInOtherCurrentLiabilities	(30,000,000)
Increase Decrease in Accrued Taxes	so_IncreaseDecreaseInAccruedTaxes	41,000,000
Increase (Decrease) in Other Operating Assets	us-gaap_IncreaseDecreaseInOtherOperatingAssets	(37,000,000)
Hedge Settlements	so_HedgeSettlements	26,000,000
Proceeds from (Repayments of) Short-term Debt	us-gaap_ProceedsFromRepaymentsOfShortTermDebt	(896,000,000)
Increase (Decrease) in Accrued Salaries	us-gaap_IncreaseDecreaseInAccruedSalaries	(21,000,000)
Net Cash Provided by (Used in) Investing Activities	us-gaap_NetCashProvidedByUsedInInvestingActivities	(559,000,000)
Increase (Decrease) in Prepaid Taxes	us-gaap_IncreaseDecreaseInPrepaidTaxes	(151,000,000)
Payments for (Proceeds from) Removal Costs	us-gaap_PaymentsForProceedsFromRemovalCosts	32,000,000
Proceeds from (Payments to) Noncontrolling Interests	us-gaap_ProceedsFromPaymentsToMinorityShareholders	0
Payments of Ordinary Dividends, Common Stock	us-gaap_PaymentsOfDividendsCommonStock	128,000,000
Proceeds from Issuance of First Mortgage Bond	us-gaap_ProceedsFromIssuanceOfFirstMortgageBond	$ 250,000,000